ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015

¨

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 001-08038

KEY ENERGY SERVICES, INC.

(Exact name of registrant as specified in its charter)

Maryland

04-2648081

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

1301 McKinney Street

Suite 1800

Houston, Texas 77010

(Address of principal executive offices, including Zip Code)

(713) 651-4300

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class

Name of Exchange on Which Registered

Common Stock, $0.10 par value

New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

Title of Class

None

Indicate by check mark if the registrant is a well-known seasoned issuer (as defined in Rule 405 of the Securities Act). Yes ¨ No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ¨ No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.) Yes þ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ¨

Accelerated filer þ

Non-accelerated filer ¨

Smaller reporting company ¨

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ

The aggregate market value of the common stock of the registrant held by non-affiliates as of June 30, 2015, based on the $1.80 per share closing price for the registrant’s common stock as quoted on the New York Stock Exchange on such date, was $240.5 million (for purposes of calculating these amounts, only directors, officers and beneficial owners of 10% or more of the outstanding common stock of the registrant have been deemed affiliates).

As of February 16, 2016, the number of outstanding shares of common stock of the registrant was 161,353,142.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement to be filed pursuant to Regulation 14A under the Securities Exchange Act of 1934 with respect to the 2016 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K.

In addition to statements of historical fact, this report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Statements that are not historical in nature or that relate to future events and conditions are, or may be deemed to be, forward-looking statements. These “forward-looking statements” are based on our current expectations, estimates and projections about Key Energy Services, Inc. and its wholly owned and controlled subsidiaries, our industry and management’s beliefs and assumptions concerning future events and financial trends affecting our financial condition and results of operations. In some cases, you can identify these statements by terminology such as “may,” “will,” “should,” “predicts,” “expects,” “believes,” “anticipates,” “projects,” “potential” or “continue” or the negative of such terms and other comparable terminology. These statements are only predictions and are subject to substantial risks and uncertainties and are not guarantees of performance. Future actions, events and conditions and future results of operations may differ materially from those expressed in these statements. In evaluating those statements, you should carefully consider the risks outlined in “Item 1A. Risk Factors.”

We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date of this report except as required by law. All of our written and oral forward-looking statements are expressly qualified by these cautionary statements and any other cautionary statements that may accompany such forward-looking statements.

Important factors that may affect our expectations, estimates or projections include, but are not limited to, the following:

•

conditions in the oil and natural gas industry, especially oil and natural gas prices and capital expenditures by oil and natural gas companies;

the amount of our debt and the limitations imposed by the covenants in the agreements governing our debt;

•

an increase in our debt service obligations due to variable rate indebtedness;

•

our ability to receive shareholder approval at the 2016 annual meeting with respect to the reverse stock split proposal;

•

delisting of our common stock from trading on the NYSE;

•

our inability to achieve our financial, capital expenditure and operational projections, including quarterly and annual projections of revenue and/or operating income and our inaccurate assessment of future activity levels, customer demand, and pricing stability which may not materialize (whether for Key as a whole or for geographic regions and/or business segments individually);

•

our ability to implement technological developments and enhancements;

•

our ability to execute our plans to withdraw from international markets outside North America;

•

our ability to achieve the benefits expected from acquisition and disposition transactions;

•

our ability to respond to changing or declining market conditions, including our ability to reduce the costs of labor, fuel, equipment and supplies employed and used in our businesses;

Key Energy Services, Inc. (NYSE: KEG), a Maryland corporation, is the largest onshore, rig-based well servicing contractor based on the number of rigs owned. References to “Key,” the “Company,” “we,” “us” or “our” in this report refer to Key Energy Services, Inc., its wholly owned subsidiaries and its controlled subsidiaries. We were organized in April 1977 and commenced operations in July 1978 under the name National Environmental Group, Inc. In December 1992, we became Key Energy Group, Inc. and we changed our name to Key Energy Services, Inc. in December 1998.

We provide a full range of well services to major oil companies, foreign national oil companies and independent oil and natural gas production companies. Our services include rig-based and coiled tubing-based well maintenance and workover services, well completion and recompletion services, fluid management services, fishing and rental services and other ancillary oilfield services. Additionally, certain of our rigs are capable of specialty drilling applications. We operate in most major oil and natural gas producing regions of the continental United States, and we have operations in Mexico and Russia. In addition, we have a technology development and control systems business based in Canada. During the second half of 2015, we ceased operations in Colombia, Ecuador and the Middle East.

The following is a description of the various products and services that we provide and our major competitors for those products and services.

Service Offerings

We revised our reportable business segments as of the fourth quarter of 2014. The revised reportable segments are U.S. Rig Services, Fluid Management Services, Coiled Tubing Services, Fishing and Rental Services and International. We also have a “Functional Support” segment associated with overhead and other costs in support of our reportable segments. Segment disclosures as of and for the year ended December 31, 2013 have been revised to reflect the change in segments. We revised our segments to reflect changes in management’s resource allocation and performance assessment in making decisions regarding our business. Our U.S. Rig Services, Fluid Management Services, Coiled Tubing Services, Fishing and Rental Services operate geographically within the United States. The International reportable segment includes our operations in Mexico, Colombia, Ecuador, Russia, Bahrain and Oman. Our Canadian subsidiary is also reflected in our International reportable segment. We evaluate the performance of our segments based on gross margin measures. All inter-segment sales pricing is based on current market conditions. See “Note 22. Segment Information” in “Item 8. Financial Statements and Supplementary Data” for additional financial information about our reportable business segments and the various geographical areas where we operate.

U.S. Rig Services

Our U.S. Rig Services include the completion of newly drilled wells, workover and recompletion of existing oil and natural gas wells, well maintenance, and the plugging and abandonment of wells at the end of their useful lives. We also provide specialty drilling services to oil and natural gas producers with certain of our larger rigs that are capable of providing conventional and horizontal drilling services. Our rigs encompass various sizes and capabilities, allowing us to service all types of wells with depths up to 20,000 feet. Many of our rigs are outfitted with our proprietary KeyView® technology, which captures and reports well site operating data and provides safety control systems. We believe that this technology allows our customers and our crews to better monitor well site operations, improves efficiency and safety, and adds value to the services that we offer.

The completion and recompletion services provided by our rigs prepare wells for production, whether newly drilled or recently extended through a workover operation. The completion process may involve selectively perforating the well casing to access production zones, stimulating and testing these zones, and installing tubular and downhole equipment. We typically provide a well service rig and may also provide other equipment to assist in the completion process. Completion services vary by well and our work may take a few days to several weeks to perform, depending on the nature of the completion.

The workover services that we provide are designed to enhance the production of existing wells and generally are more complex and time consuming than normal maintenance services. Workover services can include deepening or extending wellbores into new formations by drilling horizontal or lateral wellbores, sealing off depleted production zones and accessing previously bypassed production zones, converting former production wells into injection wells for enhanced recovery operations and conducting major subsurface repairs due to equipment failures. Workover services may last from a few days to several weeks, depending on the complexity of the workover.

Maintenance services provided with our rig fleet are generally required throughout the life cycle of an oil or natural gas well. Examples of these maintenance services include routine mechanical repairs to the pumps, tubing and other equipment, removing debris and formation material from wellbores, and pulling rods and other downhole equipment from wellbores to

identify and resolve production problems. Maintenance services are generally less complicated than completion and workover related services and require less time to perform.

Our rig fleet is also used in the process of permanently shutting-in oil or natural gas wells that are at the end of their productive lives. These plugging and abandonment services generally require auxiliary equipment in addition to a well servicing rig. The demand for plugging and abandonment services is not significantly impacted by the demand for oil and natural gas because well operators are required by state regulations to plug wells that are no longer productive.

We provide transportation and well-site storage services for various fluids utilized in connection with drilling, completions, workover and maintenance activities. We also provide disposal services for fluids produced subsequent to well completion. These fluids are removed from the well site and transported for disposal in saltwater disposal (“SWD”) wells owned by us or a third party. Demand and pricing for these services generally correspond to demand for our well service rigs.

Coiled Tubing Services involve the use of a continuous metal pipe spooled onto a large reel which is then deployed into oil and natural gas wells to perform various applications, such as wellbore clean-outs, nitrogen jet lifts, through-tubing fishing, and formation stimulations utilizing acid and chemical treatments. Coiled tubing, particularly larger diameter coil units, is also used for a number of horizontal well applications such as milling temporary isolation plugs that separate frac zones and various other pre- and post-hydraulic fracturing well preparation services.

We offer a full line of fishing services and rental equipment designed for use in providing both onshore and offshore drilling and workover services. Fishing services involve recovering lost or stuck equipment in the wellbore utilizing a broad array of “fishing tools.” Our rental tool inventory consists of drill pipe, tubulars, handling tools (including our patented Hydra-Walk® pipe-handling units and services), pressure-control equipment, pumps, power swivels, reversing units and foam air units. Our rental inventory also includes frac stack equipment used to support hydraulic fracturing operations and the associated flowback of frac fluids, proppants, oil and natural gas. We also provide well testing services.

Demand for our Fishing and Rental Services is also closely related to capital spending by oil and natural gas producers.

Our International segment includes operations in Mexico and Russia. During the second half of 2015, we ceased operations in Colombia, Ecuador and the Middle East. We provide rig-based services such as the maintenance, workover, and recompletion of existing oil wells, completion of newly-drilled wells, and plugging and abandonment of wells at the end of their useful lives in each of those international markets. In addition, in Mexico we provide drilling, coiled tubing, wireline and project management and consulting services. Our work in Mexico also requires us to provide third-party services, which vary in scope by project. We also have a technology development and control systems business based in Canada which is focused on the development of hardware and software related to oilfield service equipment controls, data acquisition and digital information flow.

In April 2015, we announced our decision to exit markets in which we participate outside of North America. Our strategy is to sell or relocate the assets of the businesses operating in these markets. In the Middle East, we operated in the Kingdom of Bahrain and Oman. On August 5, 2013, we agreed to the dissolution of AlMansoori Key Energy Services, LLC, a joint venture formed under the laws of Abu Dhabi, UAE, and the acquisition of the underlying business for $5.1 million. See “Note 2. Acquisitions” in“Item 8. Financial Statements and Supplementary Data” for further discussion. As of December 31, 2015, we sold our subsidiary in Bahrain and certain assets in Oman, Ecuador and Colombia and are no longer operating in these markets. We are currently in discussions to sell our subsidiary in Russia.

Our Russian operations provide drilling, workover, and reservoir engineering services. On April 9, 2013, we completed the acquisition of the remaining 50% noncontrolling interest in OOO Geostream Services Group (“Geostream”), a limited liability company incorporated in the Russian Federation, for $14.6 million. We now own 100% of Geostream. See “Note 2. Acquisitions” in“Item 8. Financial Statements and Supplementary Data” for further discussion.

Functional Support Segment

Our Functional Support segment includes unallocated overhead costs associated with sales, safety and administrative support for our U.S. and International reporting segments.

Management Update

On February 18, 2016, we filed a Current Report on Form 8-K disclosing that, as part of our succession plan approved by our Board of Directors (the “Board”), as of March 1, 2016 (1) Richard J. Alario, the Company’s current Chief Executive Officer, would retire and, in connection therewith, resign from all positions with the Company and its Board, (2) the number of members of the Board would be decreased to ten from eleven and (3) Robert Drummond would succeed Mr. Alario as the Company’s President and Chief Executive Officer.

On February 29, 2016, the Board, with Mr. Alario’s and Mr. Drummond’s concurrence, delayed the effective date of the foregoing actions to the earlier of (1) April 1, 2016 or (2) the first business day immediately following the day that the company files its Annual Report on Form 10-K for the fiscal year ended December 31, 2015.

Equipment Overview

We categorize our rigs and equipment as marketed or stacked. We consider a marketed rig or piece of equipment to be a unit that is working, on standby, or down for repairs but with work orders assigned to it or that is available for work. A stacked rig or piece of equipment is a unit that is in the remanufacturing process and could not be put to work without significant investment in repairs and additional equipment or we intend to salvage the unit for parts, sell the unit or scrap the unit. The definitions of marketed and stacked are used for the majority of our equipment.

Rigs

As mentioned above, our fleet is diverse and allows us to work on all types of wells, ranging from very shallow wells to wells as deep as 20,000 feet. Typically, higher horsepower (“HP”) rigs will be utilized on deep wells while lower HP rigs will be used on shallow wells. In most cases, these rigs can be reassigned to other regions should market conditions warrant the transfer of equipment. The following table summarizes our rigs based on horsepower (“HP”) as of December 31, 2015:

Coiled tubing uses a spooled continuous metal pipe that is injected downhole in oil and gas wells in order to convey tools, log, stimulate, clean-out and perform other intervention functions. Typically, larger diameter coiled tubing is able to service longer lateral horizontal wells. The table below summarizes our Coiled Tubing Services fleet by pipe diameter as of December 31, 2015:

Pipe Diameter

< 2"

≥ 2"

Total

Marketed

17

19

36

Stacked

3

12

15

Total

20

31

51

Fluid Management Services

We have an extensive and diverse fleet of oilfield transportation service vehicles. We broadly define an oilfield transportation service vehicle as any heavy-duty, revenue-generating vehicle weighing over one ton. Our transportation fleet includes vacuum trucks, winch trucks, hot oilers and other vehicles, including kill trucks and various hauling and transport trucks. The table below summarizes our Fluid Management Services fleet as of December 31, 2015:

Marketed

Stacked

Total

Truck Type

Vacuum Trucks

383

251

634

Winch Trucks

53

48

101

Hot Oil Trucks

86

60

146

Kill Trucks

89

42

131

Other

14

13

27

Total

625

414

1,039

Disposal Wells

As part of our Fluid Management Services, we provide disposal services for fluids produced subsequent to well completion. These fluids are removed from the well site and transported for disposal in SWD wells. The table below summarizes our SWD facilities, and brine and freshwater stations by state as of December 31, 2015:

Owned

Leased(1)

Total

Location

Arkansas

1

1

2

Louisiana

3

—

3

New Mexico

1

9

10

North Dakota

1

1

2

Texas

29

28

57

Total

35

39

74

(1)

Includes SWD facilities as “leased” if we own the wellbore for the SWD but lease the land. In other cases, we lease both the wellbore and the land. Lease terms vary among different sites, but with respect to some of the SWD facilities for which we lease the land and own the wellbore, the land owner has an option under the land lease to retain the wellbore at the termination of the lease.

Other Business Data

Raw Materials

We purchase a wide variety of raw materials, parts and components that are made by other manufacturers and suppliers for our use. We are not dependent on any single source of supply for those parts, supplies or materials.

Our customers include major oil companies, foreign national oil companies, and independent oil and natural gas production companies. During the years ended December 31, 2015, 2014 and 2013, Chevron Texaco Exploration and Production accounted for approximately 15% of our consolidated revenue. No other customer accounted for more than 10% of our consolidated revenue in the years ended December 31, 2015, 2014 or 2013.

No customers accounted for more than 10% of our total accounts receivable as of December 31, 2015 and 2014.

Competition and Other External Factors

The markets in which we operate are highly competitive. Competition is influenced by such factors as price, capacity, availability of work crews, and reputation and experience of the service provider. We believe that an important competitive factor in establishing and maintaining long-term customer relationships is having an experienced, skilled and well-trained work force. We devote substantial resources toward employee safety and training programs. In addition, we believe that our proprietary KeyView® system provides important safety enhancements. We believe many of our larger customers place increased emphasis on the safety, performance and quality of the crews, equipment and services provided by their contractors. Although we believe customers consider all of these factors, price is often the primary factor in determining which service provider is awarded the work. However, in numerous instances, we secure and maintain work for large customers for which efficiency, safety, technology, size of fleet and availability of other services are of equal importance to price.

The demand for our services and price we receive fluctuates, primarily in relation to the price (or anticipated price) of oil and natural gas, which, in turn, is driven for the most part by the supply of, and demand for, oil and natural gas. Generally, as supply of those commodities decreases and demand increases, service and maintenance requirements increase as oil and natural gas producers attempt to maximize the productivity of their wells in a higher priced environment. However, in a lower oil and natural gas price environment, demand for service and maintenance generally decreases as oil and natural gas producers decrease their activity. In particular, the demand for new or existing field drilling and completion work is driven by available investment capital for such work. Because these types of services can be easily “started” and “stopped,” and oil and natural gas producers generally tend to be less risk tolerant when commodity prices are low or volatile, we may experience a more rapid decline in demand for well maintenance services compared with demand for other types of oilfield services. Furthermore, in a low commodity price environment, fewer well service rigs are needed for completions, as these activities are generally associated with drilling activity.

The level of our revenues, earnings and cash flows are substantially dependent upon, and affected by, the level of U.S. and international oil and natural gas exploration, development and production activity, as well as the equipment capacity in any particular region.

Seasonality

Our operations are impacted by seasonal factors. Historically, our business has been negatively impacted during the winter months due to inclement weather, fewer daylight hours and holidays. During the summer months, our operations may be impacted by tropical or other inclement weather systems. During periods of heavy snow, ice or rain, we may not be able to operate or move our equipment between locations, thereby reducing our ability to provide services and generate revenues. In addition, the majority of our equipment works only during daylight hours. In the winter months when days become shorter, this reduces the amount of time that our assets can work and therefore has a negative impact on total hours worked. Lastly, during the fourth quarter, we historically have experienced significant slowdown during the Thanksgiving and Christmas holiday seasons and demand sometimes slows during this period as our customers exhaust their annual spending budgets.

Patents, Trade Secrets, Trademarks and Copyrights

We own numerous patents, trademarks and proprietary technology that we believe provide us with a competitive advantage in the various markets in which we operate or intend to operate. We have devoted significant resources to developing technological improvements in our well service business and have sought patent protection both inside and outside the United States for products and methods that appear to have commercial significance. All the issued patents have varying remaining durations and begin expiring between 2016 and 2033. The most notable of our technologies include numerous patents surrounding our KeyView® system.

We own several trademarks that are important to our business both in the United States and in foreign countries. In general, depending upon the jurisdiction, trademarks are valid as long as they are in use, or their registrations are properly maintained and they have not been found to become generic. Registrations of trademarks can generally be renewed indefinitely as long as the trademarks are in use. While our patents and trademarks, in the aggregate, are of considerable importance to maintaining our competitive position, no single patent or trademark is considered to be of a critical or essential nature to our business.

We also rely on a combination of trade secret laws, copyright and contractual provisions to establish and protect proprietary rights in our products and services. We typically enter into confidentiality agreements with our employees, strategic partners and suppliers and limit access to the distribution of our proprietary information.

Employees

As of December 31, 2015, we employed approximately 3,800 persons in our U.S. operations and approximately 500 additional persons in Mexico, Colombia, Ecuador, the Middle East, Russia and Canada. Our domestic employees are not represented by a labor union and are not covered by collective bargaining agreements. In Mexico, we have entered into a collective bargaining agreement that applies to our workers in Mexico performing work under our Pemex contracts. As noted below in “Item 1A. Risk Factors,” we have historically experienced a high employee turnover rate. We have not experienced any significant work stoppages associated with labor disputes or grievances and consider our relations with our employees to be generally satisfactory.

Governmental Regulations

Our operations are subject to various federal, state and local laws and regulations pertaining to health, safety and the environment. We cannot predict the level of enforcement of existing laws or regulations or how such laws and regulations may be interpreted by enforcement agencies or court rulings in the future. We also cannot predict whether additional laws and regulations affecting our business will be adopted, or the effect such changes might have on us, our financial condition or our business. The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our operations are subject and for which a lack of compliance may have a material adverse impact on our results of operations, financial position or cash flows. We believe that we are in material compliance with all such laws.

Environmental Regulations

Our operations routinely involve the storage, handling, transport and disposal of bulk waste materials, some of which contain oil, contaminants and other regulated substances. Various environmental laws and regulations require prevention, and where necessary, cleanup of spills and leaks of such materials, and some of our operations must obtain permits that limit the discharge of materials. Failure to comply with such environmental requirements or permits may result in fines and penalties, remediation orders and revocation of permits.

Hazardous Substances and Waste

The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, referred to as “CERCLA” or the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct of certain defined persons, including current and prior owners or operators of a site where a release of hazardous substances occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be jointly and severally liable for the costs of cleaning up the hazardous substances, for damages to natural resources and for the costs of certain health studies.

In the course of our operations, we occasionally generate materials that are considered “hazardous substances” and, as a result, may incur CERCLA liability for cleanup costs. Also, claims may be filed for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants. We also generate solid wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended, or “RCRA,” and comparable state statutes.

Although we use operating and disposal practices that are standard in the industry, hydrocarbons or other wastes may have been released at properties owned or leased by us now or in the past, or at other locations where these hydrocarbons and wastes were taken for treatment or disposal. Under CERCLA, RCRA and analogous state laws, we could be required to clean up contaminated property (including contaminated groundwater), or to perform remedial activities to prevent future contamination.

Air Emissions

The Clean Air Act, as amended, or “CAA,” and similar state laws and regulations restrict the emission of air pollutants and also impose various monitoring and reporting requirements. These laws and regulations may require us to obtain approvals or permits for construction, modification or operation of certain projects or facilities and may require use of emission controls.

Global Warming and Climate Change

Some scientific studies suggest that emissions of greenhouse gases (including carbon dioxide and methane) may contribute to warming of Earth’s atmosphere. While we do not believe our operations raise climate change issues different from those generally raised by commercial use of fossil fuels, legislation or regulatory programs that restrict greenhouse gas emissions in areas where we conduct business could increase our costs in order to comply with any new laws.

We operate facilities that are subject to requirements of the Clean Water Act, as amended, or “CWA,” and analogous state laws that impose restrictions and controls on the discharge of pollutants into navigable waters. Spill prevention, control and counter-measure requirements under the CWA require implementation of measures to help prevent the contamination of navigable waters in the event of a hydrocarbon spill. Other requirements for the prevention of spills are established under the Oil Pollution Act of 1990, as amended, or “OPA,” which applies to owners and operators of vessels, including barges, offshore platforms and certain onshore facilities. Under OPA, regulated parties are strictly and jointly and severally liable for oil spills and must establish and maintain evidence of financial responsibility sufficient to cover liabilities related to an oil spill for which such parties could be statutorily responsible.

Occupational Safety and Health Act

We are subject to the requirements of the federal Occupational Safety and Health Act, as amended, or “OSHA,” and comparable state laws that regulate the protection of employee health and safety. OSHA’s hazard communication standard requires that information about hazardous materials used or produced in our operations be maintained and provided to employees and state and local government authorities.

Saltwater Disposal Wells

We operate SWD wells that are subject to the CWA, Safe Drinking Water Act, and state and local laws and regulations, including those established by the Underground Injection Control Program of the Environmental Protection Agency (“EPA”), which establishes the minimum program requirements. Most of our SWD wells are located in Texas. We also operate SWD wells in Arkansas, Louisiana, New Mexico and North Dakota. Regulations in these states require us to obtain an Underground Injection Control permit to operate each of our SWD wells. The applicable regulatory agency may suspend or modify one or more of our permits if our well operations are likely to result in pollution of freshwater, substantial violation of permit conditions or applicable rules, or if the well leaks into the environment.

Access to Company Reports

Our Web site address is www.keyenergy.com, and we make available free of charge through our Web site our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports, as soon as reasonably practicable after such materials are electronically filed with or furnished to the Securities and Exchange Commission (“SEC”). Our Web site also includes general information about us, including our Corporate Governance Guidelines and charters for the committees of our board of directors. Information on our Web site or any other Web site is not a part of this report.

ITEM 1A. RISK FACTORS

In addition to the other information in this report, the following factors should be considered in evaluating us and our business.

Oil and natural gas prices began a rapid and substantial decline in the fourth quarter of 2014. Depressed commodity price conditions persisted and worsened during 2015 and that trend has continued into 2016. As a result, demand for our products and services has declined substantially, and the prices we are able to charge our customers for our products and services have also declined substantially. These trends materially and adversely affected our results of operations, cash flows and financial condition during 2015 and, unless conditions in our industry improve, this trend will continue during 2016 and potentially beyond.

We had substantial net losses during 2014 and 2015, and, during 2015, our cash flow used by operations was $22.4 million. If industry conditions do not improve, we may continue to suffer net losses and negative cash flows from operations.

Although we pursued a number of initiatives during 2015 to improve our liquidity and financial position and are continuing to pursue other initiatives, there can be no assurance that we will be able to successfully consummate these initiatives or that they will be successful to improve our financial condition and liquidity.

Our business is cyclical and depends on conditions in the oil and natural gas industry, especially oil and natural gas prices and capital expenditures by oil and natural gas companies. A continuation of the depressed state of our industry, tight credit markets and disruptions in the U.S. and global economies and financial systems may adversely impact our business.

Prices for oil and natural gas historically have been volatile as a result of changes in the supply of, and demand for, oil and natural gas and other factors. The significant decline in oil and natural gas prices that began in 2014 and continued throughout 2015 caused many of our customers to significantly reduce drilling, completion and other production activities and related spending on our products and services in 2015. Many exploration and production companies have already announced plans to further reduce spending and activity levels in 2016; thus, we expect this trend to continue and potentially worsen in 2016 and potentially beyond. In addition, the reduction in demand from our customers has resulted in an oversupply of many of the services and products we provide, and such oversupply has substantially reduced the prices we can charge our customers for our services.

We depend on our customers’ willingness to make capital expenditures to explore for, develop and produce oil and natural gas. Therefore, weakness in oil and natural gas prices (or the perception by our customers that oil and natural gas prices will remain reduced or will continue to decrease in the future) has and may continue to result in a reduction in the utilization of our equipment and in lower rates for our services. In addition to adversely affecting us, the continuation and worsening of these conditions have resulted and may continue to result in a material adverse impact on certain of our customers’ liquidity and financial position resulting in further spending reductions, delays in payment of, or non-payment of, amounts owing to us and similar impacts. These conditions have had and may continue to have an adverse impact on our financial conditions, results of operations and cash flows, and it is difficult to predict how long the current depressed commodity price environment will continue.

Many factors affect the supply of and demand for oil and natural gas and, therefore, influence product prices, including:

•

prices, and expectations about future prices, of oil and natural gas;

•

domestic and worldwide economic conditions;

•

domestic and foreign supply of and demand for oil and natural gas;

•

the price and quantity of imports of foreign oil and natural gas including the ability of OPEC to set and maintain production levels for oil;

•

the cost of exploring for, developing, producing and delivering oil and natural gas;

•

the level of excess production capacity, available pipeline, storage and other transportation capacity;

•

lead times associated with acquiring equipment and products and availability of qualified personnel;

•

the expected rates of decline in production from existing and prospective wells;

•

the discovery rates of new oil and gas reserves;

•

federal, state and local regulation of exploration and drilling activities and equipment, material or supplies that we furnish;

•

public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities;

•

weather conditions, including hurricanes that can affect oil and natural gas operations over a wide area and severe winter weather that can interfere with our operations;

•

political instability in oil and natural gas producing countries;

•

advances in exploration, development and production technologies or in technologies affecting energy consumption;

•

the price and availability of alternative fuel and energy sources;

•

uncertainty in capital and commodities markets; and

•

changes in the value of the U.S. dollar relative to other major global currencies.

Spending by exploration and production companies has also been, and may continue to be, impacted by conditions in the capital markets. Limitations on the availability of capital, and higher costs of capital, for financing expenditures have contributed to exploration and production companies making materially significant reductions to capital budgets and such limitations may continue if oil and natural gas prices remain at current levels or decrease further. Such cuts in spending have curtailed, and may continue to curtail, drilling programs as well as discretionary spending on well services, which has resulted, and may continue to result, in a reduction in the demand for our services, the rates we can charge and the utilization of our assets. Moreover, reduced discovery rates of new oil and natural gas reserves, and a decrease in the development rate of reserves in our market areas whether due to increased governmental regulation, limitations on exploration and drilling activity or other factors, have had, and may continue to have, a material adverse impact on our business, even in a stronger oil and natural gas price environment.

A substantial decline in oil and natural gas prices generally leads to decreased spending by our customers. While higher oil and natural gas prices generally lead to increased spending by our customers, sustained high energy prices can be an impediment to economic growth, and can therefore negatively impact spending by our customers. Our customers also take into account the volatility of energy prices and other risk factors by requiring higher returns for individual projects if there is higher perceived risk. Any of these factors could affect the demand for oil and natural gas and could have a material adverse effect on our business, financial condition, results of operations and cash flow.

The amount of our debt and the covenants in the agreements governing our debt could negatively impact our financial condition, results of operations and business prospects.

As of December 31, 2015, we had $964.9 million of total debt. Our level of indebtedness, and the covenants contained in the agreements governing our debt, could have important consequences for our operations, including:

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making it more difficult for us to satisfy our obligations under the agreements governing our indebtedness and increasing the risk that we may default on our debt obligations;

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requiring us to dedicate a substantial portion of our cash flow from operations to required payments on indebtedness, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities;

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limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes and other activities;

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limiting management's flexibility in operating our business;

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limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

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diminishing our ability to withstand successfully a downturn in our business or the economy generally;

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placing us at a competitive disadvantage against less leveraged competitors; and

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making us vulnerable to increases in interest rates, because certain of our debt has variable interest rates.

As more fully described in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources, each of our ABL Facility, our Term Loan Facility and our Indenture contain affirmative and negative covenants, including financial ratios and tests, with which we must comply. These covenants include, among others, covenants that restrict our ability to take certain actions without the permission of the holders of our indebtedness, including the incurrence of debt, the granting of liens, the making of investments, the payment of dividends and the sale of assets, and the financial ratios and tests include, among others, a requirement that we comply with a minimum liquidity covenant, an asset coverage ratio and, during certain periods, a fixed charge coverage ratio. In addition, under our Term Loan Facility and ABL Facility, we are required to take certain steps to perfect the security interest in the Term Priority Collateral within specified periods following the closing of those facilities.

Our ability to satisfy required financial covenants, ratios and tests in our debt agreements can be affected by events beyond our control, including commodity prices, demand for our services, the valuation of our assets, costs incurred in connection with resolving our FCPA investigation as well as prevailing economic, financial and industry conditions, and we can offer no assurance that we will be able to remain in compliance with such covenants or that the holders of our indebtedness will not seek to assert that we are not in compliance with our covenants. A breach of any of these covenants, ratios or tests could result in a default under our indebtedness. If we default, lenders under our ABL Facility will no longer be obligated to extend credit to us and they, as well as the trustee for our outstanding notes and the administrative agent under our Term Loan Facility, could declare all amounts of outstanding debt together with accrued interest, to be immediately due and payable. The results of such actions would have a significant negative impact on our results of operations, financial position and cash flows, and absent strategic alternatives such as refinancing or restructuring our indebtedness or capital structure, we would not have sufficient liquidity to repay all of our outstanding indebtedness. If such a result were to occur, we may be forced into bankruptcy or forced to seek bankruptcy protection to restructure our business and capital structure and may have to liquidate our assets and may receive less than the value at which those assets are carried on our financial statements.

We may incur more debt and long-term lease obligations in the future.

The agreements governing our long-term debt restrict, but do not prohibit, us from incurring additional indebtedness and other obligations in the future. As of December 31, 2015, we had $964.9 million of total debt.

An increase in our level of indebtedness could exacerbate the risks described in the immediately preceding risk factor and the occurrence of any of such events could result in a material adverse effect on our business, financial condition, results of operations, and business prospects.

We may not be able to generate sufficient cash flow to meet our debt service and other obligations.

Our ability to make payments on our indebtedness and to fund planned capital expenditures and other costs of our operations depends on our ability to generate cash in the future. This, to a large extent, is subject to conditions in the oil and natural gas industry, including commodity prices, demand for our services and the prices we are able to charge for our services, general economic and financial conditions, competition in the markets in which we operate, the impact of legislative and regulatory actions on how we conduct our business and other factors, all of which are beyond our control. During fiscal year 2015, we had negative cash flows from operations, and this trend could continue if conditions in our industry continue or worsen.

In light of the ongoing depressed conditions in our industry and our financial condition, we continue to explore alternatives to improve our liquidity. We may not be able to implement any such a transaction or alternative, if necessary, on commercially reasonable terms or at all, and, even if we are successful in implementing a strategic transaction or alternative, such transaction or alternative may not be successful in allowing us to meet our debt obligations. If we are unable to generate sufficient cash flow to satisfy our debt or other obligations, or to implement a strategic transaction or alternative, our creditors could potentially force us into bankruptcy or we could be forced to seek bankruptcy protection to restructure our business and capital structure, in which case we could be forced to liquidate our assets and may receive less than the value at which those assets are carried on our financial statements. Even if we are able to implement a strategic transaction or alternative, such transaction or alternative may impose onerous terms on us. Additionally, we have a significant amount of secured indebtedness that is senior to our unsecured indebtedness and a significant amount of total indebtedness that is senior to our existing common stock in our capital structure. As a result, we believe that implementation of a strategic transaction or alternative or a bankruptcy proceeding could result in a limited recovery for unsecured noteholders, if any, and place equity holders at significant risk of losing all of their interests in our company.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under our ABL Facility bear interest at variable rates, exposing us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease.

Our bylaws contain provisions that may prevent or delay a change in control.

Our bylaws contain certain provisions designed to enhance the ability of our board of directors to respond to unsolicited attempts to acquire control of the Company. These provisions:

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establish a classified board of directors, providing for three-year staggered terms of office for all members of our board of directors;

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set limitations on the removal of directors;

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enable our board of directors to set the number of directors and to fill vacancies on the board occurring between stockholder meetings; and

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set limitations on who may call a special meeting of stockholders.

These provisions may have the effect of entrenching management and may deprive investors of the opportunity to sell their shares to potential acquirers seeking control of the Company at a premium over prevailing prices. This potential inability to obtain a control premium could reduce the price of our common stock.

We may be unable to implement price increases or maintain existing prices on our core services.

We periodically seek to increase the prices of our services to offset rising costs and to generate higher returns for our stockholders. Currently, the prices we are able to charge for our services and the demand for such services are severely depressed. Even when industry conditions are favorable, we operate in a very competitive industry and as a result, we are not always successful in raising, or maintaining our existing prices. Additionally, during periods of increased market demand, a significant amount of new service capacity, including new well service rigs, fluid hauling trucks, coiled tubing units and new fishing and rental equipment, may enter the market, which also puts pressure on the pricing of our services and limits our ability to increase or maintain prices. Furthermore, during periods of declining pricing for our services, we may not be able to reduce our costs accordingly, which could further adversely affect our profitability.

Even when we are able to increase our prices, we may not be able to do so at a rate that is sufficient to offset such rising costs. In periods of high demand for oilfield services, a tighter labor market may result in higher labor costs. During such periods, our labor costs could increase at a greater rate than our ability to raise prices for our services. Also, we may not be able to successfully increase prices without adversely affecting our activity levels. The inability to maintain our prices or to increase our prices as costs increase could have a material adverse effect on our business, financial position and results of operations.

We participate in a capital-intensive industry. We may not be able to finance future growth of our operations or future acquisitions.

Our activities require substantial capital expenditures. If our cash flow from operating activities and borrowings under our ABL Facility (as defined below) are not sufficient to fund our capital expenditure budget, we would be required to reduce these expenditures or fund these expenditures through debt or equity or alternative financing plans, such as refinancing or restructuring our debt or selling assets.

Our ability to raise debt or equity capital or to refinance or restructure our debt will depend on the condition of the capital markets and our financial condition at such time, among other things. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. We currently have very little ability to raise new capital or refinance our indebtedness due to our financial condition and covenants in our debt instruments and, as a result, we have undertaken efforts to curtail our spending, which may limit our ability to grow our business and our ability to sustain or improve our profits may be adversely affected. Any of the foregoing consequences could materially and adversely affect our business, financial condition, results of operations and prospects.

Increased labor costs or the unavailability of skilled workers could hurt our operations.

Companies in our industry, including us, are dependent upon the available labor pool of skilled employees. We compete with other oilfield services businesses and other employers to attract and retain qualified personnel with the technical skills and experience required to provide our customers with the highest quality service. We are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions, and which can increase our labor costs or subject us to liabilities to our employees. A shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations could make it more difficult for us to attract and retain personnel and could require us to enhance our wage and benefits packages. Labor costs may increase in the future or we may not be able to reduce wages when demand and pricing falls, and such changes could have a material adverse effect on our business, financial condition and results of operations.

Our future financial results could be adversely impacted by asset impairments or other charges.

We have recorded goodwill impairment charges and asset impairment charges in the past. We periodically evaluate our long-lived assets, including our property and equipment, indefinite-lived intangible assets, and goodwill for impairment. In performing these assessments, we project future cash flows on a discounted basis for goodwill, and on an undiscounted basis for other long-lived assets, and compare these cash flows to the carrying amount of the related assets. These cash flow projections are based on our current operating plans, estimates and judgmental assumptions. We perform the assessment of potential impairment on our goodwill and indefinite-lived intangible assets at least annually in the fourth quarter, or more often if events and circumstances warrant. We perform the assessment of potential impairment for our property and equipment whenever facts and circumstances indicate that the carrying value of those assets may not be recoverable due to various external or internal factors. During 2015, we recorded $722.1 million in impairment charges, and if conditions in our industry do not improve or worsen, we could record additional impairment charges in future periods, which could have a material adverse effect on our financial position and results of operations.

Our business involves certain operating risks, which are primarily self-insured, and our insurance may not be adequate to cover all insured losses or liabilities we might incur in our operations.

Our operations are subject to many hazards and risks, including the following:

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accidents resulting in serious bodily injury and the loss of life or property;

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liabilities from accidents or damage by our fleet of trucks, rigs and other equipment;

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pollution and other damage to the environment;

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reservoir damage;

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blow-outs, the uncontrolled flow of natural gas, oil or other well fluids into the atmosphere or an underground formation; and

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fires and explosions.

If any of these hazards occur, they could result in suspension of operations, damage to or destruction of our equipment and the property of others, or injury or death to our or a third party's personnel.

We self-insure against a significant portion of these liabilities. For losses in excess of our self-insurance limits, we maintain insurance from unaffiliated commercial carriers. However, our insurance may not be adequate to cover all losses or liabilities that we might incur in our operations. Furthermore, our insurance may not adequately protect us against liability from all of the hazards of our business. As a result of market conditions, premiums and deductibles for certain of our insurance

policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. We also are subject to the risk that we may be unable to maintain or obtain insurance of the type and amount we desire at a reasonable cost. If we were to incur a significant liability for which we were uninsured or for which we were not fully insured, it could have a material adverse effect on our financial position, results of operations and cash flows.

We operate in a highly competitive industry, with intense price competition, which may intensify as our competitors expand their operations.

The market for oilfield services in which we operate is highly competitive and includes numerous small companies capable of competing effectively in our markets on a local basis, as well as several large companies that possess substantially greater financial resources than we do. Contracts are traditionally awarded on the basis of competitive bids or direct negotiations with customers.

The principal competitive factors in our markets are product and service quality and availability, responsiveness, experience, technology, equipment quality, reputation for safety and price. The competitive environment has intensified as recent mergers among exploration and production companies have reduced the number of available customers. The fact that drilling rigs and other vehicles and oilfield services equipment are mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry. We may be competing for work against competitors that may be better able to withstand industry downturns and may be better suited to compete on the basis of price, retain skilled personnel and acquire new equipment and technologies, all of which could affect our revenues and profitability.

Compliance with new regulations regarding the use of “conflict minerals” could limit the supply and increase the cost of certain metals used in manufacturing our products.

In accordance with Section 1502 of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 (the “Dodd-Frank Act”) the SEC new disclosure requirements, which became effective in 2014, for manufacturers of products containing certain minerals which are mined from the Democratic Republic of Congo and adjoining countries. These “conflict minerals” are commonly found in metals used in the manufacture of semiconductors. Manufacturers are also required to disclose their efforts to prevent the sourcing of such minerals and metals produced from them. One of our wholly-owned subsidiaries manufactures certain products that are covered by these requirements. The implementation of these new regulations may limit the sourcing and availability of some of the metals used in the manufacture of our products. The regulations may also reduce the number of suppliers who provide conflict-free metals, and may affect our ability to obtain the metals in sufficient quantities or at competitive prices. Finally, some of our customers may elect to disqualify us as a supplier if we are unable to verify that the metals used in our products are free of conflict minerals.

We are subject to the economic, political and social instability risks of doing business in certain foreign countries.

We currently have operations based in Mexico and Russia and we own a technology development and control systems business based in Canada. As a result, we are exposed to risks of international operations, including:

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increased governmental ownership and regulation of the economy in the markets in which we operate;

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inflation and adverse economic conditions stemming from governmental attempts to reduce inflation, such as imposition of higher interest rates and wage and price controls;

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economic and financial instability of national oil companies;

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increased trade barriers, such as higher tariffs and taxes on imports of commodity products;

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exposure to foreign currency exchange rates;

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exchange controls or other currency restrictions;

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war, civil unrest or significant political instability;

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restrictions on repatriation of income or capital;

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expropriation, confiscatory taxation, nationalization or other government actions with respect to our assets located in the markets where we operate;

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governmental policies limiting investments by and returns to foreign investors;

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labor unrest and strikes;

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deprivation of contract rights; and

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restrictive governmental regulation and bureaucratic delays.

The occurrence of one or more of these risks may:

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negatively impact our results of operations;

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restrict the movement of funds and equipment to and from affected countries; and

Our wholly owned subsidiary, Geostream, provides drilling, workover and reservoir engineering services in Russia. Continued political instability, deteriorating macroeconomic conditions, economic sanctions and actual or threatened military action related to the annexation of the Ukrainian territory of Crimea could have a material adverse effect on our subsidiary’s operations in the region and on the result of operations of our International segment.

If there is a failure to comply with the Foreign Corrupt Practices Act (“FCPA”) and similar laws, it could have a negative impact on our ongoing operations.

Our ability to comply with the FCPA and similar laws is dependent on the success of our compliance program, including our ability to continue to manage our agents, affiliates and business partners, and supervise, train and retain competent employees. Our compliance program is also dependent on the efforts of our employees to comply with applicable law and our Business Code of Conduct. We could be subject to sanctions and civil and criminal prosecution as well as fines and penalties in the event of a finding of violation of the FCPA or similar laws by us or any of our employees.

The current inquiries into issues related to compliance with the FCPA and similar laws may have a negative impact on our ongoing operations.

In January 2014, the SEC advised Key that it is investigating possible violations involving business activities of Key's operations in Russia. In April 2014, we became aware of an allegation involving our Mexico operations that, if true, could potentially constitute a violation of certain of our policies, including our Code of Business Conduct, the FCPA and other applicable laws. In 2014 and 2015, a Special Committee of the Board of Directors concluded an independent investigation into these matters, as well as a review of certain aspects of the Company’s operations and a risk assessment with regard to our other international locations. The Department of Justice (“DOJ”) is also conducting investigations of these matters, and we are cooperating with both the SEC and DOJ investigations. See Item 3. Legal Proceedings for a more detailed discussion of these investigations.

We have incurred, and may continue to incur, legal and other expenses in connection with the Special Committee and government investigations and related compliance activities. In addition, our reputation and our ability to obtain new business or retain existing business from our current and potential clients in the relevant foreign jurisdictions could be adversely affected by the outcome of, or publicity relating to, the investigations, which could have a negative impact on our results of operations.

Historically, we have experienced a high employee turnover rate. Any difficulty we experience replacing or adding workers could adversely affect our business.

We believe that the high turnover rate in our industry is attributable to the nature of oilfield services work, which is physically demanding and performed outdoors. As a result, workers may choose to pursue employment in fields that offer a more desirable work environment at wage rates that are competitive with ours. The potential inability or lack of desire by workers to commute to our facilities and job sites, as well as the competition for workers from competitors or other industries, are factors that could negatively affect our ability to attract and retain workers. We may not be able to recruit, train and retain an adequate number of workers to replace departing workers. The inability to maintain an adequate workforce could have a material adverse effect on our business, financial condition and results of operations.

We may not be successful in implementing and maintaining technology development and enhancements. New technology may cause us to become less competitive.

The oilfield services industry is subject to the introduction of new drilling and completion techniques and services using new technologies, some of which may be subject to patent protection. As competitors and others use or develop new technologies in the future, we may be placed at a competitive disadvantage. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors have greater financial, technical and personnel resources that may allow them to implement new technologies before we can. If we are unable to develop and implement new technologies or products on a timely basis and at competitive cost, our business, financial condition, results of operations and cash flows could be adversely affected.

A component of our business strategy is to incorporate the KeyView® system, our proprietary technology, into our well service rigs. The inability to successfully develop, integrate and protect this technology could:

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limit our ability to improve our market position;

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increase our operating costs; and

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limit our ability to recoup the investments made in this technological initiative.

The loss of or a substantial reduction in activity by one or more of our largest customers could materially and adversely affect our business, financial condition and results of operations.

One customer accounted for more than 10% of our total consolidated revenues for the year ended December 31, 2015, and our ten largest customers represented approximately 51% of our consolidated revenues for the period. The loss of or a substantial reduction in activity by one or more of these customers could have an adverse effect on our business, financial condition and results of operations.

Potential adoption of future state or federal laws or regulations surrounding the hydraulic fracturing process could make it more difficult to complete oil or natural gas wells and could materially and adversely affect our business, financial condition and results of operations.

Many of our customers utilize hydraulic fracturing services during the life of a well. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in underground formations where water, sand and other additives are pumped under high pressure into the formation. Although we are not a provider of hydraulic fracturing services, many of our services complement the hydraulic fracturing process.

Legislation has been introduced in Congress to provide for broader federal regulation of hydraulic fracturing operations and the reporting and public disclosure of chemicals used in the fracturing process. Additionally, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the Safe Drinking Water Act and in May 2012 issued draft guidance for fracturing operations that involved diesel fuels. If additional levels of regulation or permitting requirements were imposed through the adoption of new laws and regulations, our customers' business and operations could be subject to delays and increased operating and compliance costs, which could negatively impact the number of active wells in the marketplaces we serve. New regulations addressing hydraulic fracturing and chemical disclosure have been approved or are under consideration by a number of states and some municipalities have sought to restrict or ban hydraulic fracturing within their jurisdictions. The adoption of future federal, state or municipal laws regulating the hydraulic fracturing process could negatively impact our business, financial condition and results of operations.

We may incur significant costs and liabilities as a result of environmental, health and safety laws and regulations that govern our operations.

Our operations are subject to U.S. federal, state and local and foreign laws and regulations that impose limitations on the discharge of pollutants into the environment and establish standards for the handling, storage and disposal of waste materials, including toxic and hazardous wastes. To comply with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various governmental authorities. While the cost of such compliance has not been significant in the past, new laws, regulations or enforcement policies could become more stringent and significantly increase our compliance costs or limit our future business opportunities, which could have a material adverse effect on our financial condition and results of operations.

Our operations pose risks of environmental liability, including leakage from our operations to surface or subsurface soils, surface water or groundwater. Some environmental laws and regulations may impose strict liability, joint and several liability, or both. Therefore, in some situations, we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, third parties without regard to whether we caused or contributed to the conditions. Actions arising under these laws and regulations could result in the shutdown of our operations, fines and penalties, expenditures for remediation or other corrective measures, and claims for liability for property damage, exposure to hazardous materials, exposure to hazardous waste or personal injuries. Sanctions for noncompliance with applicable environmental laws and regulations also may include the assessment of administrative, civil or criminal penalties, revocation of permits, temporary or permanent cessation of operations in a particular location and issuance of corrective action orders. Such claims or sanctions and related costs could cause us to incur substantial costs or losses and could have a material adverse effect on our business, financial condition, results of operations and cash flow. Additionally, an increase in regulatory requirements on oil and natural gas exploration and completion activities could significantly delay or interrupt our operations. Increasing regulatory expansion could adversely impact costs associated with our offshore Fishing and Rental Services.

The scope of regulation of our services may increase in light of the April 2010 Macondo accident and resulting oil spill in the Gulf of Mexico, including possible increases in liabilities or funding requirements imposed by governmental agencies. In 2012, the Bureau of Safety and Environmental Enforcement, or “BSEE”, expanded its regulatory oversight beyond oil and gas operators to include service and equipment contractors. In addition, U.S. federal law imposes on certain entities deemed to be “responsible parties” a variety of regulations related to the prevention of oil spills, releases of hazardous substances, and liability for removal costs and natural resource, real property and certain economic damages arising from such incidents. Some of these laws may impose strict and/or joint and several liability for certain costs and damages without regard to the conduct of the parties. As a provider of services and rental equipment for offshore drilling and workover services, we may be deemed a “responsible party” under federal law. The implementation of such laws and the adoption and implementation of future

regulatory initiatives, or the specific responsibilities that may arise from such initiatives may subject us to increased costs and liabilities, which could interrupt our operations or have an adverse effect on our revenue or results of operations.

Severe weather could have a material adverse effect on our business.

Our business could be materially and adversely affected by severe weather. Our customers' oil and natural gas operations located in Louisiana and parts of Texas may be adversely affected by hurricanes and tropical storms, resulting in reduced demand for our services. Furthermore, our customers' operations may be adversely affected by seasonal weather conditions. Adverse weather can also directly impede our own operations. Repercussions of severe weather conditions may include:

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curtailment of services;

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weather-related damage to facilities and equipment, resulting in suspension of operations;

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inability to deliver equipment, personnel and products to job sites in accordance with contract schedules; and

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loss of productivity.

These constraints could delay our operations and materially increase our operating and capital costs. Unusually warm winters may also adversely affect the demand for our services by decreasing the demand for natural gas.

Acquisitions and divestitures - we may not be successful in identifying, making and integrating acquisitions or limiting ongoing costs associated with the operations we divest.

An important component of our growth strategy is to make acquisitions that will strengthen our core services or presence in selected markets. The success of this strategy will depend, among other things, on our ability to identify suitable acquisition candidates, to negotiate acceptable financial and other terms, to timely and successfully integrate acquired business or assets into our existing businesses and to retain the key personnel and the customer base of acquired businesses. Any future acquisitions could present a number of risks, including but not limited to:

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incorrect assumptions regarding the future results of acquired operations or assets or expected cost reductions or other synergies expected to be realized as a result of acquiring operations or assets;

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failure to successfully integrate the operations or management of any acquired operations or assets in a timely manner;

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failure to retain or attract key employees;

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diversion of management's attention from existing operations or other priorities;

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the inability to implement promptly an effective control environment;

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potential impairment charges if purchase assumptions are not achieved or market conditions decline;

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the risks inherent in entering markets or lines of business with which the company has limited or no prior experience; and

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inability to secure sufficient financing, sufficient financing on economically attractive terms, that may be required for any such acquisition or investment.

Our business plan anticipates, and is based upon our ability to successfully complete and integrate, acquisitions of other businesses or assets in a timely and cost effective manner. Our failure to do so could adversely affect our business, financial condition or results of operations.

We also make strategic divestitures from time to time. In the case of divestitures, we may agree to indemnify acquiring parties for certain liabilities arising from our former businesses. These divestitures may also result in continued financial involvement in the divested businesses, including through guarantees, service level agreements, or other financial arrangements, following the transaction. Lower performance by those divested businesses could affect our future financial results if there is contingent consideration associated.

Various state governments and regional organizations comprising state governments are considering enacting new legislation and promulgating new regulations governing or restricting the emission of greenhouse gases, or “GHG”, from stationary sources, which may include our equipment and operations. At the federal level, the EPA has already issued regulations that require us to establish and report an inventory of GHG emissions. The EPA also has established a GHG permitting requirement for large stationary sources and may lower the threshold of the permitting program, which could include our equipment and operations. Legislative and regulatory proposals for restricting GHG emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect demand for natural gas and oil. The potential increase in our operating costs could include new or increased costs to obtain permits, operate and maintain our equipment and facilities, install new emission controls on our equipment and facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our GHG emissions and administer and manage a GHG emissions program.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation could reduce demand for oil and natural gas. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for oil and natural gas. Management cannot predict the impact of the changing demand for oil and natural gas services and products, and any major changes may have a material effect on our business, financial condition, results of operations and cash flows.

The Company has received a notice of failure to comply with the NYSE continued listing standard related to the minimum trading price of its common stock. If the Company is unable to avoid the delisting of its common stock from the NYSE, it could have a material adverse effect on the liquidity and trading price of the Company’s common stock.

On September 2, 2015, Key Energy Services, Inc. was notified by the New York Stock Exchange (the “NYSE”) that it is not in compliance with the continued listing standards set forth in Section 802.01C of the NYSE Listed Company Manual because the average closing price of the Company’s common stock was less than $1.00 over a consecutive 30 trading-day period.

Under the NYSE Listed Company Manual, a listed company is generally afforded a six-month period following receipt of the NYSE deficiency notice to regain compliance, after which the NYSE will commence suspension of trading and delisting procedures. However, if the Company’s plan to cure the stock price deficiency requires stockholder approval, the Company can avoid delisting procedures as long as it obtains stockholder approval of the reverse stock split at its next annual meeting and promptly implements the reverse stock split following the meeting. Regaining compliance requires, on the last trading day of any calendar month, a company’s common stock price per share and 30 trading-day average closing share price to be at least $1.00. During this six month period, and if necessary, any additional period in order to obtain stockholder approval at the Company’s next annual meeting, a company’s common stock will continue to be traded on the NYSE, subject to compliance with other continued listing requirements and further subject to the discretion of the NYSE to commence delisting procedures against a company’s common stock for other reasons, such as selling for an abnormally low price. Although the Company intends to submit the reverse stock split to its stockholders at the next annual meeting in order to cure the stock price deficiency and return to compliance with the NYSE continued listing requirement, the Company can provide no assurance that this measure will be successful.

In addition, the Company's common stock could be delisted pursuant to Section 802.01D of the NYSE Listed Company Manual if the trading price of the Company's stock is deemed by the NYSE to be “abnormally low.” In this event, the Company would not have an opportunity to cure the stock price deficiency, and the Company's shares would be immediately suspended from trading on the NYSE. While there is no formal definition of “abnormally low” in the NYSE rules, we understand that the NYSE has recently delisted the common stock of issuers when it trades below $0.16 per share. The Company’s common stock has recently traded as low as $0.17 per share and we can offer no assurance that continued trading of the Company’s common stock at this level or a lower level would not be deemed “abnormally low” by the NYSE, which would result in immediate suspension and subsequent delisting. In addition, the NYSE will promptly initiate suspension and delisting procedures if the NYSE determines that we have an average global market capitalization over a consecutive 30 trading-day period of less than $15.0 million.

If the Company’s common stock ultimately were to be delisted for any reason, it could negatively impact the Company by, among other things, (i) reducing the liquidity and market price of the Company’s common stock; (ii) reducing the number of investors willing to hold or acquire the Company’s common stock, which could further harm the performance of the Company’s common stock and negatively impact the Company’s ability to raise equity financing; (iii) limiting the Company’s ability to use a registration statement to offer and sell freely tradable securities, thereby preventing the Company from accessing the public capital markets; and (iv) impairing the Company’s ability to provide equity incentives to its employees.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

We lease office space for our principal executive offices in Houston, Texas. We also lease local office space in the various countries in which we operate. Additionally, we own or lease numerous rig facilities, storage facilities, truck facilities and sales and administrative offices throughout the geographic regions in which we operate. We lease temporary facilities to house employees in regions where infrastructure is limited. In connection with our Fluid Management Services, we operate a number of owned and leased SWD facilities, and brine and freshwater stations. Our leased properties are subject to various lease terms and expirations.

We believe all properties that we currently occupy are suitable for their intended uses. We believe that our current facilities are sufficient to conduct our operations. However, we continue to evaluate the purchase or lease of additional properties or the consolidation of our properties, as our business requires.

The following table shows our active owned and leased properties, as well as active SWD facilities, categorized by geographic region as of December 31, 2015:

Region

Office, Repair &

Service and Other(1)

SWDs, Brine and

Freshwater Stations(2)

Operational Field

Services Facilities

United States

Owned

13

35

86

Leased

42

39

48

International

Owned

—

—

—

Leased

6

—

4

TOTAL

61

74

138

(1)

Includes 21 residential properties leased in the United States and one residential property leased outside the United States used to house employees.

(2)

Includes SWD facilities as “leased” if we own the wellbore for the SWD but lease the land. In other cases, we lease both the wellbore and the land. Lease terms vary among different sites, but with respect to some of the SWD facilities for which we lease the land and own the wellbore, the land owner has an option under the land lease to retain the wellbore at the termination of the lease.

ITEM 3.LEGAL PROCEEDINGS

We are subject to various suits and claims that have arisen in the ordinary course of business. We do not believe that the disposition of any of our ordinary course litigation will result in a material adverse effect on our consolidated financial position, results of operations or cash flows.

Between May of 2013 and June of 2014, five lawsuits (four class actions and one enforcement action) were filed in California involving alleged violations of California's wage and hour laws. In general, the lawsuits allege failure to pay wages, including overtime and minimum wages, failure to pay final wages upon employment terminations in a timely manner, failure to reimburse reasonable and necessary business expenses, failure to provide wage statements consistent with California law, and violations of the California meal and break period laws, among other claims. Two of the five cases have been consolidated in United States District Court for the Central District of California. On December 22, 2015, that court issued an order granting in part and denying in part a class certification motion. The court certified a class of hourly paid, non-exempt oilfield employees who allege they did not receive reimbursement for all business expenses and allege they did not receive all rest breaks required by California law. The court did not determine whether Key is liable to any of the class members. The court in one of the remaining cases that had been stayed pending outcome of the class certification motion recently issued an order lifting the stay. The fourth case is waiting for a decision regarding whether it will move forward in California state court or in federal court. The fifth case is an enforcement action for civil penalties based on California’s Private Attorneys General Act, which is pending in California state court. We have investigated the claims in all five lawsuits, and intend to vigorously defend them. At this time, we cannot estimate any possible loss or range of loss.

In January 2014, the SEC advised Key that it is investigating possible violations of the U.S. Foreign Corrupt Practices Act (“FCPA”) involving business activities of Key’s operations in Russia. In April 2014, we became aware of an allegation involving our Mexico operations that, if true, could potentially constitute a violation of certain of our policies, including our Code of Business Conduct, the FCPA and other applicable laws. On May 30, 2014, Key voluntarily disclosed the allegation involving our Mexico operations and certain information from the Company’s initial investigation to both the SEC and Department of Justice (“DOJ”). A Special Committee of our Board of Directors conducted an independent investigation regarding this allegation as well as possible violations of the FCPA involving business activities of our operations in Russia. The Special Committee’s independent review, which also included a review of certain aspects of the Company’s operations in Colombia, as well as a risk assessment with regard to our other international locations, has been completed. We are continuing to cooperate with the SEC and DOJ. At this time we are unable to predict the ultimate resolution of these matters with these agencies and, accordingly, cannot reasonably estimate any possible loss or range of loss.

In August 2014, two class action lawsuits were filed in the U.S. District Court, Southern District of Texas, Houston Division, individually and on behalf of all other persons similarly situated against the Company and certain officers of the Company, alleging violations of federal securities laws, specifically, violations of Section 10(b) and Rule 10(b)-5, Section 20(a) of the Securities Exchange Act of 1934. Those lawsuits were styled as follows: Sean Cady, Individually and on Behalf of All Other Persons Similarly Situated v. Key Energy Services, Inc., Richard J. Alario, and J. Marshall Dodson, No. 4:14-cv-2368, filed on August 15, 2014; and Ian W. Davidson, Individually and on Behalf of All Other Persons Similarly Situated v. Key Energy Services, Inc., Richard J. Alario, and J. Marshall Dodson, No. 4.14-cv-2403, filed on August 21, 2014. On December

11, 2014, the Court entered an order that consolidated the two lawsuits into one action, along with any future filed tag-along actions brought on behalf of purchasers of Key Energy Services, Inc. common stock. The order also appointed Inter-Local Pension Fund as the lead plaintiff in the class action and approved the law firm of Spector Roseman Kodroff & Willis, P.C. as lead counsel for the consolidated class and Kendall Law Group, LLP, as local counsel for the consolidated class. The lead plaintiff filed the consolidated amended complaint on February 13, 2015. Among other changes, the consolidated amended complaint adds Taylor M. Whichard III and Newton W. Wilson III as defendants, and seeks to represent a class of purchasers of the Company's stock between September 4, 2012 and July 17, 2014. Defendants Key Energy Services, Inc., Richard J. Alario, J. Marshall Dodson and Newton W. Wilson III filed a Motion to Dismiss on April 14, 2015. Defendant Taylor M. Whichard III filed a Joinder in Motion and Motion to Dismiss on the same date. Lead plaintiff filed an opposition to that motion, and all defendants filed reply briefs in support of the motion. The court has not ruled upon it. Because this case is in the early stages, we cannot predict the outcome at this time. Accordingly, we cannot estimate any possible loss or range of loss.

In addition, in a letter dated September 4, 2014, a purported shareholder of the Company demanded that the Board commence an independent internal investigation into and legal proceedings against each member of the Board, a former member of the Board and certain officers of the Company for alleged violations of Maryland and/or federal law. The letter alleges that the Board and senior officers breached their fiduciary duties to the Company, including the duty of loyalty and due care, by (i) improperly accounting for goodwill, (ii) causing the Company to potentially violate the FCPA, resulting in an investigation by the SEC, (iii) causing the Company to engage in improper conduct related to the Company’s Russia operations; and (iv) making false statements regarding, and failing to properly account for, certain contracts with Pemex. As described in the letter, the purported shareholder believes that the legal proceedings should seek recovery of damages in an unspecified amount allegedly sustained by the Company. The Board of Directors referred the demand letter to the Special Committee. We cannot predict the outcome of this matter.

In March 2015, two collective action lawsuits were filed in the Southern District of Texas, Corpus Christi Division, individually and on behalf of all others similarly situated, alleging violations of the Fair Labor Standards Act of 1938 (“FLSA”). We agreed to conditional certification in the first lawsuit and notice of the case issued to 56 putative class members. Roughly 20% of the eligible putative class members timely filed a notice of consent to join the lawsuit. We will soon begin merit-based discovery in the first lawsuit, which will last at least six months. We also agreed to conditional certification in the second lawsuit and notice of the case recently issued to 14 putative class members. Four putative class members, including the named plaintiff, have filed a notice of consent to join the lawsuit thus far and there is approximately a month and a half remaining for others to join. The parties will begin merit-based discovery in the second case as soon as the notice period closes. Because the cases are in the early stages, we cannot predict the outcome of these cases at this time. Accordingly, we cannot estimate any possible loss or range of loss for either case.

In May 2015, a class and collective action lawsuit was filed in the Southern District of Texas, Houston Division, individually and on behalf of all others similarly situated, alleging violations of the FLSA and the New Mexico Minimum Wage Act. We agreed to conditional certification of a putative class and notice issued to 174 putative class members. The notice period closed in early February and roughly 15% of eligible putative class members timely filed a consent to join the lawsuit. The parties will soon begin merit-based discovery in this case, which will likely last six to nine months. Because the case is in the early stages, we cannot predict the outcome at this time. Accordingly, we cannot estimate any possible loss or range of loss for this case.

In November 2015, the Santa Barbara County District Attorney filed a criminal complaint against two former employees and Key, and specifically alleging three counts of violations of California Labor Code section 6425(a) against Key. The complaint seeks unspecified penalties against Key related to an October 12, 2013 accident which resulted in the death of one Key employee at a drilling site near Santa Maria, California. An arraignment was held on February 10, 2016, where Key and its former employees pleaded not guilty to all charges. Because the matter is in early stages, we cannot predict the outcome at this time. Accordingly, we cannot estimate any possible loss or range of loss.

On or about November 23, 2015, the North Dakota Industrial Commission ("NDIC") filed a notice in the county of Burleigh County, ND alleging statutory violations by Key Energy Services, LLC, as operator of two salt water disposal wells in the state of North Dakota. The NDIC has pled for approximately $888,000 in fines and costs. The Company is currently in discussions with the NDIC and is not able to estimate any possible loss or range of loss at this time.

Our common stock is traded on the New York Stock Exchange (“NYSE”) under the symbol “KEG.” As of February 16, 2016, there were 560 registered holders of 161,353,142 issued and outstanding shares of common stock. This number of registered holders does not include holders that have shares of common stock held for them in “street name”, meaning that the shares are held for their accounts by a broker or other nominee. In these instances, the brokers or other nominees are included in the number of registered holders, but the underlying holders of the common stock that have shares held in “street name” are not. The following table sets forth the reported high and low closing price of our common stock for the periods indicated:

High

Low

Year Ended December 31, 2015

1st Quarter

$

2.39

$

1.32

2nd Quarter

2.69

1.72

3rd Quarter

1.60

0.47

4th Quarter

0.78

0.42

High

Low

Year Ended December 31, 2014

1st Quarter

$

9.24

$

7.15

2nd Quarter

10.45

7.96

3rd Quarter

9.19

4.84

4th Quarter

4.82

1.05

The following Performance Graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that we specifically incorporate it by reference into such filing.

The following performance graph compares the performance of our common stock to the PHLX Oil Service Sector Index, the Russell 2000 Index, old peer group and new peer group as established by management.

The graph below compares the cumulative five-year total return to holders of our common stock with the cumulative total returns of the PHLX Oil Service Sector, the listed Russell 2000 Index and our new and old peer groups. The graph assumes that the value of the investment in our common stock and each index (including reinvestment of dividends) was $100 at December 31, 2010 and tracks the return on the investment through December 31, 2015.

* $100 invested on December 31, 2010 in stock or index, including reinvestment of dividends. Fiscal years ended December 31.

Dividend Policy

There were no dividends declared or paid on our common stock for the years ended December 31, 2015, 2014 and 2013. Under the terms of our indenture, ABL Facility and Term Loan Facility (defined below), we must meet certain financial covenants before we may pay dividends. We do not currently intend to pay dividends.

Issuer Purchases of Equity Securities

During the fourth quarter of 2015, we repurchased an aggregate of 92,750 shares of our common stock. The repurchases were to satisfy tax withholding obligations that arose upon vesting of restricted stock. Set forth below is a summary of the share repurchases:

Period

Total Number of Shares Purchased

Average Price Paid Per Share(1)

October 1, 2015 to October 31, 2015

69,022

$

0.54

November 1, 2015 to November 30, 2015

3,174

$

0.50

December 1, 2015 to December 31, 2015

20,554

$

0.48

(1)

The price paid per share with respect to the tax withholding repurchases was determined using the closing prices on the applicable vesting date, as quoted on the NYSE.

The following table sets forth information as of December 31, 2015 with respect to equity compensation plans (including individual compensation arrangements) under which our common stock is authorized for issuance. The material features of each of these plans are described in “Note 19. Share-Based Compensation” in “Item 8. Financial Statement and Supplementary Date.”

Includes 811,550 of shares that may be issued upon the exercise of stock options and 92,883 of shares that may be issued upon vesting of restricted stock units (“RSUs”). Stock-settled stock appreciation rights (“SARs”) are excluded as the fair market value of our SARs was zero as of December 31, 2015.

(3)

RSUs do not have an exercise price; therefore RSUs are excluded from weighted average exercise price of outstanding awards.

(4)

Represents the number of shares remaining available for grant under the 2014 Incentive Plan as of December 31, 2015. If any common stock underlying an unvested award that is canceled, forfeited or is otherwise terminated without delivery of shares, then such shares will again be available for issuance under the 2014 Incentive Plan.

ITEM 6. SELECTED FINANCIAL DATA

The following historical selected financial data as of and for the years ended December 31, 2011 through December 31, 2015 has been derived from our audited financial statements included in “Item 8. Financial Statements and Supplementary Data.” For the year ended December 31, 2011 we have reclassified the historical results of operations of our Argentina business as discontinued operations. The historical selected financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements and related notes thereto included in “Item 8. Financial Statements and Supplementary Data.”

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes thereto in “Item 8. Financial Statements and Supplementary Data.” The discussion below contains forward-looking statements that are based upon our current expectations and are subject to uncertainty and changes in circumstances including those identified in “Cautionary Note Regarding Forward-Looking Statements” above. Actual results may differ materially from these expectations due to potentially inaccurate assumptions and known or unknown risks and uncertainties. Such forward-looking statements should be read in conjunction with our disclosures under “Item 1A. Risk Factors.”

We provide a full range of well services to major oil companies, foreign national oil companies and independent oil and natural gas production companies to produce, maintain and enhance the flow of oil and natural gas throughout the life of a well. These services include rig-based and coiled tubing-based well maintenance and workover services, well completion and recompletion services, fluid management services, fishing and rental services and other ancillary oilfield services. Additionally, certain of our rigs are capable of specialty drilling applications. We operate in most major oil and natural gas producing regions of the continental United States, and we have operations in Mexico and Russia. In addition, we have a technology development and control systems business based in Canada. During the second half of 2015, we ceased operations in Colombia, Ecuador and the Middle East.

The demand for our services fluctuates, primarily in relation to the price (or anticipated price) of oil and natural gas, which, in turn, is driven primarily by the supply of, and demand for, oil and natural gas. Generally, as supply of those commodities decreases and demand increases, service and maintenance requirements increase as oil and natural gas producers attempt to maximize the productivity of their wells in a higher priced environment. However, in the lower oil and natural gas price environment that has persisted since late 2014, demand for service and maintenance has decreased as oil and natural gas producers decrease their activity. In particular, the demand for new or existing field drilling and completion work is driven by available investment capital for such work and our customers have significantly curtailed their capital spending in both 2015 and 2016. Because these types of services can be easily “started” and “stopped,” and oil and natural gas producers generally tend to be less risk tolerant when commodity prices are low or volatile, we may experience a more rapid decline in demand for well maintenance services compared with demand for other types of oilfield services. Further, in a lower-priced environment, fewer well service rigs are needed for completions, as these activities are generally associated with drilling activity.

Business and Growth Strategies

Focus on Horizontal Well Services

Over the past several years the number of horizontal wells, particularly horizontal oil wells, drilled in the U.S. has increased significantly. Horizontal wells tend to involve a higher degree of service intensity associated with their drilling and completion, and we believe ultimately the maintenance required over their lifetime as well. We believe that many of these wells are entering the phase of their life where more maintenance services are required to stem declines and maintain production. We further believe that over future periods, the market for maintenance on the installed base of horizontal oil wells will grow. To capitalize on this growing market segment we have built and acquired new equipment, including more capable rigs and coiled tubing units, upgraded existing equipment capable of providing services integral to the completion and maintenance of horizontal wellbores and acquired frac stack equipment used to support completion of the horizontal wellbore. We also expanded our service offerings into unconventional shale regions where horizontal activity is most prevalent including the Bakken shale, the Eagle Ford shale and others. As horizontal wells have become more prevalent in the Permian Basin, we have expanded our operations and assets best suited for horizontal well maintenance, with all of our service offerings in that market. Additionally, while we have invested in the assets used to service our customer’s well site needs, we have also strengthened our sales and service efforts to better identify and meet the needs of our customers. We intend to continue our focus on the expansion of horizontal well service offerings, particularly production maintenance related services, in existing markets and into new markets in the United States.

Navigate Market Uncertainties

We operate in a cyclical business where our customers’ spending is largely driven by the prices received on their sale of oil and natural gas production. In the current depressed commodity price environment, demand for our services and the price we receive for our services has fallen significantly and competition for the remaining market activity has increased. In response, we have stacked older and more costly to operate equipment and reduced the amount of capital invested in the business for growth or replacement of equipment. We have also taken steps to lower our cost to operate, reducing headcount and the costs of labor. Additionally, we have taken steps to reduce the fixed costs in our business and will continue to do so. These actions have been taken in an effort to preserve our liquidity pending an increase in activity levels.

After evaluating market opportunities presented by the secular trend of aging horizontal wellbores and options for the allocation of the Company’s capital, the Board of Directors and management have refined the Company’s strategy to focus on North American production enhancement. As such, in the second quarter of 2015, we began our evaluation of alternatives and took steps to exit markets in which we participate outside of North America, either by sale or relocation of assets. We have sold our subsidiary in Bahrain and in Oman, Colombia and Ecuador, we have sold the property, plant and equipment, net and inventories and have ceased operations. We are currently in discussion to sell our Russian subsidiary and expect the sale to occur in the first half of 2016.

PERFORMANCE MEASURES

The Baker Hughes U.S. rig count data, which is publicly available on a weekly basis, is often used as a coincident indicator of overall Exploration and Production (“E&P”) company spending and broader oilfield activity. In assessing overall activity in the U.S. onshore oilfield service industry in which we operate, we believe that the Baker Hughes U.S. land drilling rig count is the best barometer of E&P companies' capital spending and resulting activity levels. Historically, our activity levels have been highly correlated to U.S. onshore capital spending by our E&P company customers as a group.

Year

WTI Cushing Crude

Oil(1)

NYMEX Henry Hub

Natural Gas(1)

Average Baker Hughes

U.S. Land Drilling Rigs(2)

2011

$

94.87

$

4.03

1,846

2012

$

94.05

$

2.75

1,871

2013

$

97.98

$

3.73

1,705

2014

$

93.17

$

4.37

1,804

2015

$

48.66

$

2.62

943

(1)

Represents the average of the monthly average prices for each of the years presented. Source: U.S. Energy Information Administration, Bloomberg.

Internally, we measure activity levels for our well servicing operations primarily through our rig and trucking hours. Generally, as capital spending by E&P companies increases, demand for our services also rises, resulting in increased rig and trucking services and more hours worked. Conversely, when activity levels decline due to lower spending by E&P companies, we generally provide fewer rig and trucking services, which results in lower hours worked. The following table presents our quarterly rig and trucking hours from 2013 through 2015.

Rig Hours

Trucking Hours

Key’s U.S.

Working Days(1)

U.S.

International

Total

2015:

First Quarter

271,005

36,950

307,955

418,032

62

Second Quarter

232,169

25,555

257,724

342,271

63

Third Quarter

226,953

13,330

240,283

309,601

64

Fourth Quarter

203,252

8,279

211,531

247,979

62

Total 2015

933,379

84,114

1,017,493

1,317,883

251

2014:

First Quarter

347,047

46,090

393,137

481,353

63

Second Quarter

355,219

33,758

388,977

493,494

63

Third Quarter

365,891

34,603

400,494

506,486

64

Fourth Quarter

341,313

41,156

382,469

481,653

61

Total 2014

1,409,470

155,607

1,565,077

1,962,986

251

2013:

First Quarter

337,714

114,103

451,817

580,862

62

Second Quarter

365,956

65,280

431,236

559,584

64

Third Quarter

360,112

55,105

415,217

524,513

64

Fourth Quarter

343,626

46,553

390,179

507,636

62

Total 2013

1,407,408

281,041

1,688,449

2,172,595

252

(1)

Key's U.S. working days are the number of weekdays during the quarter minus national holidays.

MARKET CONDITIONS AND OUTLOOK

Market Conditions — Year Ended December 31, 2015

Our core businesses depend on our customers’ willingness to make expenditures to produce, develop and explore for oil and natural gas. Industry conditions are influenced by numerous factors, such as the supply of and demand for oil and natural gas, domestic and worldwide economic conditions, and political instability in oil producing countries.

The fourth quarter continued the deterioration of the oil and gas industry as persistently low commodity prices caused oilfield service activity to continue to decline. Additionally, a pronounced seasonal reduction in activity, due to holidays, fewer daylight hours and adverse weather conditions, contributed to activity declines during the quarter. E&P companies have continued to scale back capital spending in order to preserve liquidity. Further, operating expenditures, on which Key’s core production services business relies, have also been scaled down as the economics supporting this spend has eroded at current commodity prices. Key has aggressively reshaped its organizational structure and reduced its cost structure to reflect the realities of today’s market.

The Company moved closer to exiting the markets in which it participates outside of North America. All of our physical assets in Colombia, Ecuador, Bahrain and Oman have been sold or were relocated to the U.S. As it pertains to the Company’s business in Russia, we continue to work with potential buyers to finalize the due diligence and negotiate a final transaction. Once we have finalized a sale of our Russia business, our remaining operations outside of the U.S. will be limited to Mexico and our subsidiary in Canada.

The domestic oil and gas complex is now facing the challenge of how to achieve return-accretive cash flow in the face of low commodity prices. We believe that due to deferred maintenance there is a backlog of well maintenance building, though it remains unclear what set of factors will drive our customers to resume normal production maintenance activity levels. However, we believe that our customers must work on these wells to maintain the production base and further believe that the economics associated with this work make sense at an oil price lower than was enjoyed by our customers at the peak of the most recent drilling cycle. As such, we believe that our commitment to production enhancement activities will eventually provide a meaningful opportunity for us.

As we look into the first quarter, the outlook for the U.S. oilfield services landscape remains challenged. The Company will continue to identify ways to streamline its cost structure and will continue to explore ways to enhance the liquidity position of the company both internally and externally.

RESULTS OF OPERATIONS

Consolidated Results of Operations

The following table shows our consolidated results of operations for the years ended December 31, 2015, 2014 and 2013:

Year Ended December 31,

2015

2014

2013

(in thousands)

REVENUES

$

792,326

$

1,427,336

$

1,591,676

COSTS AND EXPENSES:

Direct operating expenses

714,637

1,059,651

1,114,462

Depreciation and amortization expense

180,271

200,738

225,297

General and administrative expenses

202,631

249,646

221,753

Impairment expense

722,096

121,176

—

Operating income (loss)

(1,027,309

)

(203,875

)

30,164

Interest expense, net of amounts capitalized

73,847

54,227

55,204

Other (income) loss, net

9,394

1,009

(803

)

Loss before income taxes

(1,110,550

)

(259,111

)

(24,237

)

Income tax benefit

192,849

80,483

3,064

Net loss

(917,701

)

(178,628

)

(21,173

)

Income attributable to noncontrolling interest

—

—

595

LOSS ATTRIBUTABLE TO KEY

$

(917,701

)

$

(178,628

)

$

(21,768

)

Years Ended December 31, 2015 and 2014

For the year ended December 31, 2015, our operating loss was $1.0 billion, compared to an operating loss of $203.9 million for the year ended December 31, 2014. Loss per share was $5.86 for the year ended December 31, 2015 compared to $1.16 loss per share for the year ended December 31, 2014.

Revenues

Our revenues for the year ended December 31, 2015decreased$635.0 million, or 44.5%, to $792.3 million from $1.4 billion for the year ended December 31, 2014, due to lower spending from our customers as a result of lower oil prices. These market conditions resulted in reduced customer activity and a reduction in the price received for our services. Internationally, we had lower revenue as a result of reduced customer activity in Russia and Colombia and the exit of operations in the Middle East and South America. See “Segment Operating Results — Years Ended December 31, 2015 and 2014” below for a more detailed discussion of the change in our revenues.

Direct operating expenses

Our direct operating expenses decreased$345.0 million, or 32.6%, to $714.6 million (90.2% of revenues) for the year ended December 31, 2015, compared to $1.06 billion (74.2% of revenues) for the year ended December 31, 2014. The decrease is primarily related to a decrease in employee compensation costs, fuel expense and repair and maintenance expense as we

sought to reduce our cost structure and as a result of lower activity levels. See “Segment Operating Results — Years Ended December 31, 2015 and 2014” below for a more detailed discussion of the change in our direct operating expenses.

Depreciation and amortization expense

Depreciation and amortization expense decreased$20.5 million, or 10.2%, to $180.3 million (22.8% of revenues) for the year ended December 31, 2015, compared to $200.7 million (14.1% of revenues) for the year ended December 31, 2014. The decrease is primarily attributable to the impairment of certain fixed assets and decreases in capital expenditures and lower amortization expense due to the impairment of certain intangible assets.

General and administrative expenses

General and administrative expenses decreased$47.0 million, or 18.8%, to $202.6 million (25.6% of revenues) for the year ended December 31, 2015, compared to $249.6 million (17.5% of revenues) for the year ended December 31, 2014. The decrease is primarily due to lower employee compensation costs due to reduced staffing levels and reduction in wages and lower expenses related to our FCPA investigations.

Impairment expense

During the year ended December 31, 2015, we recorded a $582.7 million impairment of goodwill, a $51.1 million impairment of fixed assets that are being held and used, a $1.5 million impairment of other intangible assets that are no longer being used, and a $86.8 million impairment of fixed assets to reduce the carrying value of assets held for sale to fair market value. During the year ended December 31, 2014, we recorded a $28.7 million impairment of goodwill and tradenames in our Russian business unit which is included in our International reporting segment and a $73.4 million impairment of goodwill and fixed assets at our Fishing and Rental Services segment and a $19.1 million impairment of goodwill at our Coiled Tubing segment.

Interest expense, net of amounts capitalized

Interest expense increased$19.6 million to $73.8 million (9.3% of revenues), for the year ended December 31, 2015, compared to $54.2 million (3.8% of revenues) for the year ended December 31, 2014. The increase is primarily related to increased borrowings and interest rate under the new Term Loan Facility in the year ended December 31, 2015 and the write-off of the remaining $0.8 million of unamortized deferred financing costs related to the 2011 Credit Facility in the second quarter of 2015.

Other loss, net

During the year ended December 31, 2015, we recognized other loss, net, of $9.4 million, compared to other loss, net, of $1.0 million for the year ended December 31, 2014. A $7.8 million allowance for the collectibility of our notes receivable related to the sale of our operations in Argentina was recorded in the year ended December 31, 2015. Our foreign exchange loss relates to U.S. dollar-denominated transactions in our foreign locations and fluctuations in exchange rates between local currencies and the U.S. dollar.

The table below presents comparative detailed information about other loss, net at December 31, 2015 and 2014:

Year Ended December 31,

2015

2014

(in thousands)

Interest income

$

(159

)

$

(82

)

Foreign exchange loss

4,153

3,733

Allowance for collectibility of notes receivable

7,705

—

Other, net

(2,305

)

(2,642

)

Total

$

9,394

$

1,009

Income tax benefit

Our income tax benefit on continuing operations was $192.8 million (17.4% effective rate) on pre-tax loss of $1.1 billion for the year ended December 31, 2015, compared to an income tax benefit of $80.5 million (31.1% effective rate) on a pre-tax loss of $259.1 million for the year ended December 31, 2014. Our effective tax rates for such periods differ from the U.S. statutory rate of 35% due to a number of factors, including the mix of profit and loss between domestic and international taxing jurisdictions and the impact of permanent items, including goodwill impairment expense and expenses subject to statutorily imposed limitations such as meals and entertainment expenses, that affect book income but do not affect taxable income and discrete tax adjustments, such as valuation allowances against deferred tax assets and tax expense or benefit recognized for uncertain tax positions.

For the year ended December 31, 2014, our operating loss was $203.9 million, compared to operating income of $30.2 million for the year ended December 31, 2013. Loss per share was $1.16 for the year ended December 31, 2014 compared to $0.14 loss per share for the year ended December 31, 2013.

Revenues

Our revenues for the year ended December 31, 2014 decreased $164.3 million, or 10.3%, to $1.4 billion from $1.6 billion for the year ended December 31, 2013, primarily due to overall lower activity in the U.S. as a result of competitive pressure and reduced customer activity. Reduced customer activity in Mexico resulted in reduced revenue in our International segment. See “Segment Operating Results — Years Ended December 31, 2014 and 2013” below for a more detailed discussion of the change in our revenues.

Direct operating expenses

Our direct operating expenses decreased $54.8 million, or 4.9%, to $1.06 billion (74.2% of revenues) for the year ended December 31, 2014, compared to $1.11 billion (70.0% of revenues) for the year ended December 31, 2013 as a result of lower variable costs, such as cost attributable to direct labor and equipment, due to reduced activity levels. See “Segment Operating Results — Years Ended December 31, 2014 and 2013” below for a more detailed discussion of the change in our direct operating expenses.

Depreciation and amortization expense

Depreciation and amortization expense decreased $24.6 million, or 10.9%, to $200.7 million (14.1% of revenues) for the year ended December 31, 2014, compared to $225.3 million (14.2% of revenues) for the year ended December 31, 2013. The decrease is primarily attributable to decreases in capital expenditures and lower amortization related to intangible assets.

General and administrative expenses

General and administrative expenses increased $27.9 million, or 12.6%, to $249.6 million (17.5% of revenues) for the year ended December 31, 2014, compared to $221.8 million (13.9% of revenues) for the year ended December 31, 2013. The increase is primarily due to legal expenses related to the FCPA investigation of $41.1 million partially offset by lower compensation costs due to reduced staffing levels.

Impairment expense

During the year ended December 31, 2014, we recorded a $28.7 million impairment of goodwill and other intangibles assets in our Russian business unit, which is included in our International reporting segment, $73.4 million impairment of fixed assets and other intangibles assets at our Fishing and Rental Services segment and a $19.1 million impairment of goodwill at our Coiled Tubing segment. No impairments were recorded in 2013.

Interest expense, net of amounts capitalized

Interest expense decreased $1.0 million to $54.2 million (3.8% of revenues), for the year ended December 31, 2014, compared to $55.2 million (3.5% of revenues) for the year ended December 31, 2013. The decrease is primarily related to reduced borrowings under the revolving credit facility for the year ended December 31, 2014 compared to 2013.

Other (income) loss, net

During the year ended December 31, 2014, we recognized other loss, net, of $1.0 million, compared to other income, net, of $0.8 million for the year ended December 31, 2013. Our foreign exchange loss relates to U.S. dollar-denominated transactions in our foreign locations and fluctuations in exchange rates between local currencies and the U.S. dollar.

The table below presents comparative detailed information about other (income) loss, net at December 31, 2014 and 2013:

Our income tax benefit on continuing operations was $80.5 million (31.1% effective rate) on pre-tax loss of $259.1 million for the year ended December 31, 2014, compared to an income tax benefit of $3.1 million (12.6% effective rate) on a pre-tax loss of $24.2 million for the year ended December 31, 2013. Our effective tax rates for such periods differ from the U.S. statutory rate of 35% due to a number of factors, including the mix of profit and loss between domestic and international taxing jurisdictions and the impact of permanent items, such as goodwill impairment expense, that affect book income but do not affect taxable income.

Noncontrolling interest

We have no noncontrolling interest holders in 2014, due to our acquisition of our remaining noncontrolling interest in our joint ventures in 2013. For the year ended December 31, 2013, we allocated $0.6 million associated with the income incurred by our joint ventures to the noncontrolling interest holders of these ventures.

Segment Operating Results

Years Ended December 31, 2015 and 2014

The following table shows operating results for each of our reportable segments for the years ended December 31, 2015 and 2014 (in thousands):

For the year ended December 31, 2015

U.S. Rig Service

Fluid Management Services

Coiled Tubing Services

Fishing and Rental Services

International

FunctionalSupport

Total

Revenues from external customers

$

377,131

$

153,153

$

89,823

$

121,883

$

50,336

$

—

$

792,326

Operating expenses

685,070

196,637

244,991

319,295

232,872

140,770

1,819,635

Operating loss

(307,939

)

(43,484

)

(155,168

)

(197,412

)

(182,536

)

(140,770

)

(1,027,309

)

For the year ended December 31, 2014

U.S. Rig Service

Fluid Management Services

Coiled Tubing Services

Fishing and Rental Services

International

FunctionalSupport

Total

Revenues from external customers

$

679,045

$

249,589

$

173,364

$

212,598

$

112,740

$

—

$

1,427,336

Operating expenses

582,658

246,262

184,183

271,542

178,172

168,394

1,631,211

Operating income (loss)

96,387

3,327

(10,819

)

(58,944

)

(65,432

)

(168,394

)

(203,875

)

U.S. Rig Services

Revenues for our U.S. Rig Services segment decreased $301.9 million, or 44.5%, to $377.1 million for the year ended December 31, 2015, compared to $679.0 million for the year ended December 31, 2014. The decrease for this segment is primarily due to lower spending from our customers as a result of lower oil prices. These market conditions resulted in reduced customer activity and a reduction in the price received for our services.

Operating expenses for our U.S. Rig Services segment were $685.1 million during the year ended December 31, 2015, which represented an increase of $102.4 million, or 17.6%, compared to $582.7 million for the year ended December 31, 2014. These expenses increased primarily as a result of a $297.7 million impairment of goodwill in 2015, partially offset by a decrease in employee compensation costs and equipment expense as we sought to reduce our cost structure and as a result of lower activity levels.

Fluid Management Services

Revenues for our Fluid Management Services segment decreased $96.4 million, or 38.6%, to $153.2 million for the year ended December 31, 2015, compared to $249.6 million for the year ended December 31, 2014. The decrease for this segment is primarily due to lower spending from our customers as a result of lower oil prices. These market conditions resulted in reduced customer activity and a reduction in the price received for our services.

Operating expenses for our Fluid Management Services segment were $196.6 million during the year ended December 31, 2015, which represented a decrease of $49.6 million, or 20.2%, compared to $246.3 million for the year ended December 31, 2014. These expenses decreased primarily as a result of a decrease in equipment expense and employee compensation costs as we sought to reduce our cost structure and as a result of lower activity levels. This decrease was partially offset by a $24.5 million impairment of goodwill recorded in 2015.

Revenues for our Coiled Tubing Services segment decreased $83.5 million, or 48.2%, to $89.8 million for the year ended December 31, 2015, compared to $173.4 million for the year ended December 31, 2014. The decrease for this segment is primarily due to lower spending from our customers as a result of lower oil prices. These market conditions resulted in reduced customer activity and a reduction in the price received for our services.

Operating expenses for our Coiled Tubing Services segment were $245.0 million during the year ended December 31, 2015, which represented an increase of $60.8 million, or 33.0%, compared to $184.2 million for the year ended December 31, 2014. These expenses increased primarily as a result of a $82.7 million impairment of goodwill and a $51.1 million impairment of fixed assets in 2015 compared to a $19.1 million impairment of goodwill in 2014, partially offset by a decrease in employee compensation costs, repair and maintenance expense and fuel costs as we sought to reduce our cost structure and as a result of lower activity levels.

Fishing and Rental Services

Revenues for our Fishing and Rental Services segment decreased $90.7 million, or 42.7%, to $121.9 million for the year ended December 31, 2015, compared to $212.6 million for the year ended December 31, 2014. The decrease for this segment is primarily due to lower spending from our customers as a result of lower oil prices. These market conditions resulted in reduced customer activity and a reduction in the price received for our services.

Operating expenses for our Fishing and Rental Services segment were $319.3 million during the year ended December 31, 2015, which represented an increase of $47.8 million, or 17.6%, compared to $271.5 million for the year ended December 31, 2014. These expenses increased primarily as a result of a $173.5 million impairment of goodwill and a $6.0 million impairment of intangible assets in 2015 compared to a $62.1 impairment of fixed assets in 2014, partially offset by a decrease in employee compensation costs, repair and maintenance expense and fuel costs as we sought to reduce our cost structure and as a result of lower activity levels.

International

Revenues for our International segment decreased $62.4 million, or 55.4%, to $50.3 million for the year ended December 31, 2015, compared to $112.7 million for the year ended December 31, 2014. The decrease was primarily attributable to lower customer activity in Russia and Colombia and the exit of operations in the Middle East and South America.

Operating expenses for our International segment increased $54.7 million, or 30.7%, to $232.9 million for the year ended December 31, 2015, compared to $178.2 million for the year ended December 31, 2014. These expenses increased primarily as a result of an increase in impairment of assets held for sale of $80.8 million and a $4.4 million impairment of goodwill in 2015 compared to a $22.4 million impairment of goodwill and $6.3 million impairment of intangible assets in 2014, partially offset by a decrease in employee compensation costs and equipment expense, primarily due to lower activity.

Functional support

Operating expenses for our Functional Support segment decreased $27.6 million, or 16.4%, to $140.8 million (17.8% of consolidated revenues) for the year ended December 31, 2015 compared to $168.4 million (11.8% of consolidated revenues) for the year ended December 31, 2014. The decrease in expense is primarily due to lower employee compensation costs due to reduced staffing levels and a decrease of $9.5 million of legal expense related to the FCPA investigations.

The following table shows operating results for each of our reportable segments for the years ended December 31, 2014 and 2013 (in thousands):

For the year ended December 31, 2014

U.S. Rig Service

Fluid Management Services

Coiled Tubing Services

Fishing and Rental Services

International

FunctionalSupport

Total

Revenues from external customers

$

679,045

$

249,589

$

173,364

$

212,598

$

112,740

$

—

$

1,427,336

Operating expenses

582,658

246,262

184,183

271,542

178,172

168,394

1,631,211

Operating income (loss)

96,387

3,327

(10,819

)

(58,944

)

(65,432

)

(168,394

)

(203,875

)

For the year ended December 31, 2013

U.S. Rig Service

Fluid Management Services

Coiled Tubing Services

Fishing and Rental Services

International

FunctionalSupport

Total

Revenues from external customers

$

673,465

$

271,709

$

193,184

$

238,611

$

214,707

$

—

$

1,591,676

Operating expenses

539,907

267,671

169,757

207,302

241,364

135,511

1,561,512

Operating income (loss)

133,558

4,038

23,427

31,309

(26,657

)

(135,511

)

30,164

U.S. Rig Services

Revenues for our U.S. Rig Services segment increased $5.6 million, or 0.8%, to $679.0 million for the year ended December 31, 2014, compared to $673.5 million for the year ended December 31, 2013. The increase in revenue is primarily due to an increase in market activity partially offset by a decrease in customer activity in California rig-based services and a decrease in customer spending.

Operating expenses for our U.S. Rig Services segment were $582.7 million during the year ended December 31, 2014, which represented an increase of $42.8 million, or 7.9%, compared to $539.9 million for the year ended December 31, 2013. These expenses increased primarily as a result of an increase in direct labor and repair and maintenance expenses related to an increase in activity.

Fluid Management Services

Revenues for our Fluid Management Services segment decreased $22.1 million, or 8.1%, to $249.6 million for the year ended December 31, 2014, compared to $271.7 million for the year ended December 31, 2013. The decrease in revenue is primarily due to lower activity and decrease in pricing due to competitive pressure.

Operating expenses for our Fluid Management Services segment were $246.3 million during the year ended December 31, 2014, which represented a decrease of $21.4 million, or 8.0%, compared to $267.7 million for the year ended December 31, 2013. The decrease in expenses is primarily related to lower direct labor expenses and fuel costs due to a decrease in activity.

Coiled Tubing Services

Revenues for our Coiled Tubing Services segment decreased $19.8 million, or 10.3%, to $173.4 million for the year ended December 31, 2014, compared to $193.2 million for the year ended December 31, 2013. The decrease in revenue is primarily due to lower activity due to competitive pressure and unscheduled down time events.

Operating expenses for our Coiled Tubing Services segment were $184.2 million during the year ended December 31, 2014, which represented an increase of $14.4 million, or 8.5%, compared to $169.8 million for the year ended December 31, 2013. The increase in expenses is primarily a result of impairment of goodwill partially offset by lower direct labor expenses due to a decrease in activity.

Fishing and Rental Services

Revenues for our Fishing and Rental Services segment decreased $26.0 million, or 10.9%, to $212.6 million for the year ended December 31, 2014, compared to $238.6 million for the year ended December 31, 2013. The decrease in revenue is primarily due to lower activity due to competitive pressure.

Operating expenses for our Fishing and Rental Services segment were $271.5 million during the year ended December 31, 2014, which represented an increase of $64.2 million, or 31.0%, compared to $207.3 million for the year ended

December 31, 2013. The increase in expenses is primarily a result of the impairment of fixed assets and other intangible assets partially offset by a decrease in depreciation expense.

International

Revenues for our International segment decreased $102.0 million, or 47.5%, to $112.7 million for the year ended December 31, 2014, compared to $214.7 million for the year ended December 31, 2013. The decrease was primarily attributable to lower customer activity in Mexico.

Operating expenses for our International segment decreased $63.2 million, or 26.2%, to $178.2 million for the year ended December 31, 2014, compared to $241.4 million for the year ended December 31, 2013. These expenses decreased as a direct result of lower customer activity and severance costs in Mexico, partially offset by impairment of goodwill and tradenames in our Russian business reporting unit.

Functional support

Operating expenses for our Functional Support segment increased $32.9 million, or 24.3%, to $168.4 million (11.8% of consolidated revenues) for the year ended December 31, 2014 compared to $135.5 million (8.5% of consolidated revenues) for the year ended December 31, 2013. The increase is primarily due to increased legal expense related to the FCPA investigations, partially offset by lower employee compensation and benefit costs.

Oil and natural gas prices began a rapid and substantial decline in the fourth quarter of 2014. Depressed commodity price conditions persisted and worsened during 2015 and that trend has continued into 2016. As a result, demand for our products and services has declined substantially, and the prices we are able to charge our customers for our products and services have also declined substantially. These trends materially and adversely affected our results of operations, cash flows and financial condition during 2015 and, unless conditions in our industry improve, this trend will continue during 2016 and potentially beyond.

In response to these conditions, we have undertaken several actions detailed below in an effort to preserve and improve our liquidity and financial position.

•

On June 1, 2015, we entered into our $100 million ABL Facility due February 28, 2020 and our $315 million Term Loan Facility due June 1, 2020. At the closing, we borrowed the full amount available under the Term Loan Facility and used a portion of the proceeds to repay and terminate our prior revolving credit facility. Remaining proceeds were retained as cash to provide liquidity. As of December 31, 2015, we had no borrowings outstanding under the ABL Facility and $47.9 million of letters of credit outstanding with available borrowing capacity of $27.2 million available, as restricted by covenant constraints under our ABL Facility.

•

In April 2015, we announced our decision to exit markets in which we participate outside of North America. Our strategy is to sell or relocate the assets of the businesses operating in these markets. As of December 31, 2015, we had sold our subsidiary in Bahrain and certain assets in Oman, Ecuador and Colombia and are no longer operating in these markets. We are currently in discussions to sell our subsidiary in Russia.

•

Beginning in the first quarter of 2015, we began a series of cost cutting initiatives at both corporate and field levels, which include fixed costs, supply-chain efficiencies and headcount and wage reductions.

However, we still have substantial indebtedness and other obligations, and we may incur additional expenses and be obligated to pay fines or penalties in connection with seeking to resolve our ongoing FCPA investigation, although, at this time, we are unable to predict the ultimate resolution of this matter.

Our ability to fund our operations, pay the principal and interest on our long-term debt and to satisfy our other obligations will depend upon our available liquidity and the amount of cash flows we are able to generate from our operations. During 2015, our net cash used in operating activities was $22.4 million, and, if industry conditions do not improve, we may have negative cash flows from operations in 2016.

As of December 31, 2015, our adjusted working capital (working capital excluding the current portion of long-term debt) was $269.1 million compared to $191.9 million as of December 31, 2014. Our adjusted working capital increased during 2015 primarily as a result of the receipt of cash proceeds from the Term Loan Facility and a decrease in accounts payable and other accrued expenses partially offset by a decrease in accounts receivable and repayment of the 2011 Credit Facility.

As of December 31, 2015, we had $204.4 million of cash, of which approximately $13.7 million was held in the bank accounts of our foreign subsidiaries. As of December 31, 2015, $10.6 million of the cash held by our foreign subsidiaries was held in U.S. bank accounts and denominated in U.S. dollars. We believe that the cash held by our wholly owned foreign subsidiaries could be repatriated for general corporate use without material withholdings.

We believe that our internally generated cash flows from operations, current reserves of cash and availability under our ABL facility are sufficient to finance our cash requirements for current and future operations, budgeted capital expenditures, debt service and other obligations for the next twelve months. However, in light of the current conditions in our industry, we continue to explore alternatives to improve our liquidity. We may not, however, be able to implement any such a transaction or alternative, if necessary, on commercially reasonable terms or at all, and, even if we are successful in implementing strategic transaction or alternative, such transaction or alternative may not be successful in allowing us to meet our debt obligations. In addition, even if we are able to implement a strategic transaction or alternative, such transaction or alternative may impose onerous terms on us and/or certain of our security holders and could materially and adversely impact the interests of certain of our security holders. See Item 1A—Risk Factors—“The amount of our debt and the covenants in the agreements governing our debt could negatively impact our financial condition, results of operations and business prospects.” and “We may not be able to generate sufficient cash flow to meet our debt service and other obligations.” Our future operating performance and ability to refinance will be affected by the results of our operations, economic and capital market conditions, oil and natural gas prices and other factors, many of which are beyond our control.

Cash Flows

Cash used in operating activities was $22.4 million for the year ended December 31, 2015, compared to cash provided by operating activities of $164.2 million for the year ended December 31, 2014. Cash used by operating activities for the year ended December 31, 2015 was primarily related to net loss adjusted for noncash items and payments of accounts payable and other accrued liabilities partially offset by cash inflows related to the collection of accounts receivable. Cash provided by operating activities for the year ended December 31, 2014 was primarily related to net income adjusted for noncash items, collection of accounts receivable and an increase in accounts payable.

Cash used in investing activities was $19.4 million and $146.8 million for the years ended December 31, 2015 and 2014, respectively. Investing cash outflows during these periods consisted primarily of capital expenditures partially offset by the sales of assets. Capital expenditures primarily relate to replacement assets for our existing fleet and equipment.

Cash provided by financing activities was $218.7 million for the year ended December 31, 2015, compared to cash used in financing activities of $22.1 million during the year ended December 31, 2014. Cash provided by financing activities for the year ended December 31, 2015 primarily relates to proceeds from long-term debt partially offset by net payments on our 2011 Credit Facility. Cash used in financing activities for the year ended December 31, 2014 primarily relates to net payments on our 2011 Credit Facility.

The following table summarizes our cash flows for the years ended December 31, 2015 and 2014:

At December 31, 2015, our annual maturities on our indebtedness, consisting only of our 2021 Notes and Term Loan Facility at year-end, were as follows:

Principal Payments

(in thousands)

2016

$

3,150

2017

3,150

2018

3,150

2019

3,150

2020

300,825

2021 and thereafter

675,000

Total

$

988,425

Interest on $675.0 million of our 2021 Notes is due on March 1 and September 1 of each year. Our 2021 Notes mature on September 1, 2021. Interest paid on our 2021 Notes during 2015 and 2014 was $45.6 million. We expect to fund interest payments from cash on hand and cash generated by operations.

6.75% Senior Notes due 2021

We have outstanding $675.0 million of 6.75% Senior Notes due 2021 (the “2021 Notes”). The 2021 Notes are general unsecured senior obligations and are effectively subordinated to all of our existing and future secured indebtedness. The 2021 Notes are or will be jointly and severally guaranteed on a senior unsecured basis by certain of our existing and future domestic subsidiaries. Interest on the 2021 Notes is payable on March 1 and September 1 of each year. The 2021 Notes mature on March 1, 2021. We capitalized $4.6 million of financing costs associated with the issuance of the 2021 Notes that will be amortized over the term of the notes.

On or after March 1, 2016, the 2021 Notes will be subject to redemption at any time and from time to time at our option, in whole or in part, at the redemption prices below (expressed as percentages of the principal amount redeemed), plus accrued and unpaid interest to the applicable redemption date, if redeemed during the twelve-month period beginning on March 1 of the years indicated below:

Year

Percentage

2016

103.375

%

2017

102.250

%

2018

101.125

%

2019 and thereafter

100.000

%

At any time and from time to time prior to March 1, 2016, we may, at our option, redeem all or a portion of the 2021 Notes at a redemption price equal to 100% of the principal amount plus a premium with respect to the 2021 Notes plus accrued and unpaid interest to the redemption date. The premium is the excess of (i) the present value of the redemption price of 103.375 of the principal amount, plus all remaining scheduled interest payments due through March 1, 2016 discounted at the treasury rate plus 0.50% over (ii) the principal amount of the note. If we experience a change of control, subject to certain exceptions, we must give holders of the 2021 Notes the opportunity to sell to us their 2021 Notes, in whole or in part, at a purchase price equal to 101% of the aggregate principal amount, plus accrued and unpaid interest to the date of purchase.

We are subject to certain negative covenants under the Indenture. The Indenture limits our ability to, among other things:

•

incur additional indebtedness and issue preferred equity interests;

•

pay dividends or make other distributions or repurchase or redeem equity interests;

Substantially all of the covenants will terminate before the 2021 Notes mature if one of two specified ratings agencies assigns the 2021 Notes an investment grade rating in the future and no events of default exist under the Indenture. As of December 31, 2015, the 2021 Notes were rated below investment grade. Any covenants that cease to apply to us as a result of achieving an investment grade rating will not be restored, even if the credit rating assigned to the 2021 Notes later falls below investment grade. We were in compliance with all covenants under the Indenture at December 31, 2015.

ABL Facility

On June 1, 2015, the Company entered into a Loan and Security Agreement (the “ABL Facility”), among the Company and Key Energy Services, LLC, as the Borrowers (collectively, the “ABL Borrowers”), certain subsidiaries of the ABL Borrowers named as guarantors therein, the financial institutions party thereto from time to time as Lenders (collectively, the “ABL Lenders”), Bank of America, N.A., as Administrative Agent for the Lenders, and Bank of America, N.A. and Wells Fargo Bank, National Association, as Co-Collateral Agents for the Lenders. The ABL Facility provides for aggregate initial commitments from the ABL Lenders of $100 million (the “Commitments”) and matures on February 28, 2020.

The ABL Facility provides the ABL Borrowers with the ability to borrow up to an aggregate principal amount equal to the lesser of (i) the Commitments and (ii) the sum of (a) 85% of the value of eligible accounts receivable plus (b) 80% of the value of eligible unbilled accounts receivable, subject to a limit equal to the greater of (x) $35 million and (y) 25% of the Commitments plus (c) certain cash and cash equivalents deposited for the benefit of the ABL Lenders, subject to a limit of $15 million. The amount that may be borrowed under the ABL Facility is subject to reduction for certain reserves provided for by the ABL Facility. In addition, the percentages of accounts receivable and unbilled accounts receivable included in the calculation described above is subject to reduction to the extent of certain bad debt write-downs and similar amounts provided in the ABL Facility.

Borrowings under the ABL Facility bear interest, at the ABL Borrowers’ option, at a per annum rate equal to (i) LIBOR for 30, 60, 90, 180, or, with the consent of the ABL Lenders, 360 days, plus4.5% or (ii) a base rate equal to the sum of (a) the greatest of (x) the prime rate, (y) the Federal Funds rate, plus0.50% or (z) 30-day LIBOR, plus1.0%plus (b) 3.5%. In addition, the ABL Facility provides for unused line fees of 1.00% to 1.25% per year, depending on utilization, letter of credit fees and certain other fees.

The ABL Facility is guaranteed by certain of the Company’s existing and future subsidiaries (the “ABL Guarantors,” and together with the ABL Borrowers, the “ABL Loan Parties”). To secure their obligations under the ABL Facility, each of the ABL Loan Parties has granted to the Administrative Agent a first-priority security interest for the benefit of the ABL Lenders in its present and future accounts receivable, inventory and related assets and proceeds of the foregoing (the “ABL Priority Collateral”). In addition, the obligations of the ABL Loan Parties under the ABL Facility are secured by second-priority liens on the Term Priority Collateral (as described below under “Term Loan Facility”).

The revolving loans under the ABL Facility may be voluntarily prepaid, in whole or in part, without premium or penalty, subject to breakage or similar costs.

The ABL Facility contains certain affirmative and negative covenants, including covenants that restrict the ability of the ABL Loan Parties to take certain actions without the permission of the ABL Lenders or as permitted under the ABL Facility including the incurrence of debt, the granting of liens, the making of investments, the payment of dividends and the sale of assets. The ABL Facility also contains a requirement that the ABL Borrowers comply with a minimum liquidity covenant, an asset coverage ratio and, during certain periods, a fixed charge coverage ratio.

Under the asset coverage ratio covenant, the ABL Borrowers must maintain an asset coverage ratio of at least 1.5 to 1.0. The asset coverage ratio is generally defined as the ratio of (i) the sum of (a) the value of the Term Priority Collateral plus (b) certain cash and cash equivalents in excess of $100 million held for the benefit of the Term Loan Lenders to (ii) the sum of (a) the amount outstanding under the Term Loan Facility and, following repayment of the Term Loan Facility, the amount outstanding under the ABL Facility, plus (b) the amount of any fine or settlement in respect of the FCPA Matter (as defined in the ABL Facility) that is secured by a lien on the ABL Priority Collateral or the Term Priority Collateral (the “Asset Coverage Ratio”).

Under the fixed charge coverage ratio covenant, the ABL Borrowers must maintain a fixed charge coverage ratio of at least 1.0 to 1.0 during the period commencing on the day that availability under the ABL Facility is less than the greater of $20 million and 20% of the Commitments and continuing until the 90th day following the day that availability under the ABL Facility is greater than the greater of $20 million and 20% of the Commitments. The fixed charge coverage ratio is generally defined as the ratio of (i) EBITDA minus certain capital expenditures and cash taxes paid to (ii) the sum of cash interest expenses, scheduled principal payments on borrowed money and certain distributions. The ABL Facility permits the ABL Borrowers, in calculating EBITDA, to add back certain amounts in respect of the investigatory expenses associated with the

FCPA Matter and amounts paid in settlement of the FCPA Matter to the extent such amounts do not exceed net liquidity, defined as certain cash and cash equivalents minus the principal amount of loans outstanding under the ABL Facility.

Under the minimum liquidity covenant (the “Minimum Liquidity Covenant”), the ABL Borrowers must not permit Liquidity, defined as the sum of (i) availability under the ABL Facility plus (ii) certain unrestricted cash and cash equivalents, to be less than $100.0 million as of the last day of any fiscal quarter or immediately after any cash payment of a settlement of, or fine in connection with, the FCPA Matter.

The ABL Facility contains customary representations and warranties and conditions to borrowing, including the absence of any default or event of default, the accuracy in all material respects of the representations and warranties of the ABL Loan Parties contained in the ABL Facility and the absence of any event or circumstance that has or could reasonably be expected to have a material adverse effect.

The ABL Facility contains customary events of default, the occurrence of which entitle the ABL Lenders to accelerate the maturity of amounts outstanding under the ABL Facility and exercise other customary remedies and an event of that is triggered if, immediately after any cash payment of a settlement of the FCPA Matter (and after any cash or borrowings under the ABL Facility are used to fund such payment), (i) the Company shall fail to be in compliance with the Minimum Liquidity Covenant or (ii) if any loans under the ABL Facility are outstanding on the date of such cash payment, availability under the ABL Facility is less than 33% of the borrowing base in effect on such date.

Term Loan Facility

On June 1, 2015, the Company entered into a Term Loan and Security Agreement (the “Term Loan Facility”), among the Company, as Borrower, certain subsidiaries of the Company named as guarantors therein, the financial institutions party thereto from time to time as Lenders (collectively, the “Term Loan Lenders”), Cortland Capital Market Services LLC, as Agent for the Lenders, and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Sole Lead Arranger and Sole Bookrunner.

On June 1, 2015, the Company and other parties thereto closed on the Term Loan Facility, the Company borrowed $315 million (prior to giving effect to an upfront discount of 3% which resulted in net proceeds to the Company, prior to expenses, of approximately $305.5 million), and the Company used a portion of such proceeds to repay its prior credit facility. The Term Loan Facility provides for an incremental facility which, subject to the agreement of one or more Term Loan Lenders or other institutional lenders agreeing to provide the additional loans and the satisfaction of certain terms and conditions, would enable the Company to borrow additional amounts under the Term Loan Facility as long as the aggregate outstanding amount of all borrowings thereunder does not exceed $400 million. The Term Loan Facility will mature on June 1, 2020, although such maturity date may, at the Company’s request, be extended by one or more of the Term Loan Lenders pursuant to the terms of the Term Loan Facility.

Borrowings under the Term Loan Facility bear interest, at the Company’s option, at a per annum rate equal to (i) LIBOR for one, two, three, six, or, with the consent of the Term Loan Lenders, 12 months, plus9.25% or (ii) a base rate equal to the sum of (a) the greatest of (x) the prime rate, (y) the Federal Funds rate, plus0.50% and (z) 30-day LIBOR, plus1.0%plus (b) 8.25%.

The Term Loan Facility is guaranteed by certain of the Company’s existing and future subsidiaries (the “Term Loan Guarantors,” and together with the Company, the “Term Loan Parties”). To secure their obligations under the Term Loan Facility, each of the Term Loan Parties has granted to the Agent a first-priority security interest for the benefit of the Term Loan Lenders in substantially all of each Term Loan Party’s assets other than certain excluded assets and the ABL Priority Collateral (the “Term Priority Collateral”). In addition, the obligations of the Term Loan Parties under the Term Loan Facility are secured by second-priority liens on the ABL Priority Collateral (as described above under “ABL Facility”).

The loans under the Term Loan Facility may be prepaid at the Company’s option, subject to the payment of a prepayment premium in certain circumstances as provided in the Term Loan Facility. The Company is required to make principal payments in the amount of $787,500 per quarter commencing with the quarter ended September 30, 2015. In addition, pursuant to the Term Loan Facility, the Company must offer to prepay term loans out of the Net Cash Proceeds (as defined in the Term Loan Facility) of certain asset sales and, for each fiscal year beginning with the Company’s fiscal year ending December 31, 2015, the Company must offer to prepay term loans in an aggregate principal amount equal to 50% of the Company’s Excess Cash Flow (as defined in the Term Loan Facility) for such fiscal year. Within 30 days following any Change of Control (as defined in the Term Loan Facility), the Company must offer to prepay all term loans (i) at a price of 101% of the amount thereof if, after giving effect to such Change of Control, the Asset Coverage Ratio is at least 1.5 to 1.0 or (ii) at a price equal to the greater of 101% of the amount thereof and the applicable prepayment premium provided for in the Term Loan Facility if, after giving effect to such Change of Control, the Asset Coverage Ratio is less than 1.5 to 1.0.

The Term Loan Facility contains customary representations and warranties and certain affirmative and negative covenants, including covenants that restrict the ability of the Term Loan Parties to take certain actions without the permission of

the Term Loan Lenders or as permitted under the Term Loan Facility including the incurrence of debt, the granting of liens, the making of investments, the payment of dividends and the sale of assets. The Term Loan Facility also contains financial covenants requiring that the Company maintain an Asset Coverage Ratio of at least 1.5 to 1.0 and that Liquidity (as defined in the Term Loan Facility) must not be less than $100 million as of the last day of any fiscal quarter or immediately after any cash payment of a settlement of, or fine in connection with, the FCPA Matter.

The Term Loan Facility contains events of default, the occurrence of which entitle the Term Loan Lenders to accelerate the maturity of amounts outstanding under the Term Loan Facility and exercise other customary remedies.

We were in compliance with covenants of the ABL Facility and Term Loan Facility as of December 31, 2015. As of December 31, 2015, we have no borrowings outstanding under the ABL Facility and $47.9 million of letters of credit outstanding with borrowing capacity of $27.2 million available subject to covenant constraints under our ABL Facility.

Our ability to fund our operations, pay the principal and interest on our long-term debt and to satisfy our other obligations will depend upon our available liquidity and the amount of cash flows we are able to generate from our operations. During 2015, cash used in operations was $22.4 million, and, if industry conditions do not improve, we may have negative cash flows from operations in 2016.

We believe that our internally generated cash flows from operations, current reserves of cash and availability under our ABL facility are sufficient to finance our cash requirements for current and future operations, budgeted capital expenditures, debt service and other obligations for the next twelve months. However, in light of the current conditions in our industry, we continue to analyze a variety of transactions and mechanisms designed to reduce our debt and improve our liquidity. Our future operating performance and ability to refinance will be affected by the results of our operations, economic and capital market conditions, oil and natural gas prices and other factors, many of which are beyond our control.

We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances. If we fail to comply with the covenants and other restrictions in the agreements governing our debt, and are unable to cure, obtain a waiver or an amendment, it could lead to an event of default and the consequent acceleration of our obligation to repay all of our outstanding debt. Our ability to comply with debt covenants and other restrictions may be affected by events beyond our control, including general economic and financial conditions.

In particular, under the terms of our indebtedness, we must comply with certain financial ratios and satisfy certain financial condition tests that could require us to take action to reduce our debt or take some other action in order to comply with them. Our ability to satisfy required financial ratios and tests can be affected by events beyond our control, including prevailing economic, financial and industry conditions, and we may not be able to continue to meet those ratios and tests in the future. A breach of any of these covenants, ratios or tests could result in a default under our indebtedness. If we default, lenders under our ABL Facility will no longer be obligated to extend credit to us and they, as well as the trustee for our outstanding notes and the administrative agent under our Term Loan Facility, could elect to declare all amounts of outstanding debt together with accrued interest, to be immediately due and payable. The results of such actions would have a significant negative impact on our results of operations, financial position and cash flows.

In addition, access to the liquidity provided by our ABL Facility is predicated upon our ability to satisfy the conditions to borrowing, which conditions require that the representations and warranties under the facility, including representations and warranties related to our solvency and the absence of a material adverse effect, remain true and correct.

The weighted average interest rates on the outstanding borrowings under the ABL Facility and Term Loan Facility for the year ended December 31, 2015 were as follows:

The Year Ended

December 31, 2015

(in thousands)

ABL Facility

—

%

Term Loan Facility

10.27

%

Senior Secured Credit Facility

On June 1, 2015, in connection with entering into the ABL Facility and the Term Loan Facility, we terminated our senior secured revolving bank credit facility, dated as of March 31, 2011, as amended through December 5, 2014 (the “2011 Credit Facility”), which was scheduled to mature no later than March 31, 2016. The 2011 Credit Facility provided for a senior secured credit facility consisting of a revolving credit facility, letter of credit sub-facility and swing line facility of up to an aggregate principal amount of $400.0 million. The 2011 Credit Facility was terminated without any prepayment penalties. The remaining unamortized deferred financing costs of $0.8 million were written off at the time of the termination.

The interest rate per annum applicable to the 2011 Credit Facility was, at our option, (i) adjusted LIBOR plus the applicable margin or (ii) the higher of (x) JPMorgan’s prime rate, (y) the Federal Funds rate plus 0.5% and (z) one-month adjusted LIBOR plus 1.0%, plus in each case the applicable margin for all other loans. The applicable margin for LIBOR loans had ranged from 225 to 300 basis points, and the applicable margin for all other loans ranges from 125 to 200 basis points, depending upon our consolidated total leverage ratio as defined in the 2011 Credit Facility. Unused commitment fees on the facility was equal to 0.5%. For the five months ended June 1, 2015 and year ended December 31, 2014, the weighted average interest rates on the outstanding borrowings under our 2011 Credit Facility was 3.14% and 2.97%, respectively.

Letter of Credit Facility

On November 7, 2013, we entered into an uncommitted, unsecured $15.0 million letter of credit facility to be used solely for the issuances of performance letters of credit. As of December 31, 2015, $2.0 million of letters of credit were outstanding under the facility.

Off-Balance Sheet Arrangements

At December 31, 2015, we did not, and we currently do not, have any off-balance sheet arrangements that have or are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Contractual Obligations

Set forth below is a summary of our contractual obligations as of December 31, 2015. The obligations we pay in future periods reflect certain assumptions, including variability in interest rates on our variable-rate obligations and the duration of our obligations, and actual payments in future periods may vary.

Payments Due by Period

Total

Less than 1

Year (2016)

1-3 Years

(2017-2019)

4-5 Years

(2020-2021)

After 5 Years

(2022+)

(in thousands)

2021 Notes

675,000

$

—

$

—

$

675,000

$

—

Interest associated with 2021 Notes

254,402

45,563

136,688

72,151

—

Term Loan Facility due 2020

313,425

3,150

9,450

300,825

—

Interest associated with Term Loan Facility(1)

31,688

7,175

21,525

2,988

—

Non-cancelable operating leases

56,405

9,712

19,428

9,638

17,627

Liabilities for uncertain tax positions

408

157

251

—

—

Equity based compensation liability

awards(2)

271

271

—

—

—

Total

$

1,331,599

$

66,028

$

187,342

$

1,060,602

$

17,627

(1)

Based on interest rates in effect at December 31, 2015.

(2)

Based on our closing stock price at December 31, 2015.

Debt Compliance

At December 31, 2015, we were in compliance with all the financial covenants under our ABL Facility, Term Loan Facility and 2021 Notes. Based on management’s current projections, we expect to be in compliance with all the covenants under our 2011 Credit Facility and 2021 Notes for the next twelve months. A breach of any of these covenants, ratios or tests could result in a default under our indebtedness. See “— Debt Service” and “Item 1A. Risk Factors”

During the year ended December 31, 2015, our capital expenditures totaled $40.8 million, primarily related to the ongoing replacement to our rig service fleet, coiled tubing units, fluid transportation equipment and rental equipment. Our capital expenditure plan for 2016 contemplates spending between $20.0 million and $30.0 million, subject to market conditions. This is primarily related to equipment replacement needs, including ongoing replacement to our rig services fleet. Our capital expenditure program for 2016 is subject to market conditions, including activity levels, commodity prices, industry capacity and specific customer needs. Our focus for 2016 will be the maximization of our current equipment fleet, but we may choose to increase our capital expenditures in 2016 to increase market share or expand our presence into a new market. We currently anticipate funding our 2016 capital expenditures through a combination of cash on hand, operating cash flow, and borrowings under our ABL Facility. Should our operating cash flows or activity levels prove to be insufficient to fund our currently planned capital spending levels, management expects it will adjust our capital spending plans accordingly. We may also incur capital expenditures for strategic investments and acquisitions.

Acquisitions

Geostream

On April 9, 2013, we completed the acquisition of the remaining 50% noncontrolling interest in Geostream for $14.6 million. We now own 100% of Geostream.

AlMansoori Key Energy Services, LCC

On August 5, 2013, we agreed to the dissolution of AlMansoori Key Energy Services, LLC, a joint venture formed under the laws of Abu Dhabi, UAE, and the acquisition of the underlying business for $5.1 million. During the fourth quarter of 2014 the joint venture was duly liquidated and the $5.1 million was transferred to AlMansoori.

We anticipate that acquisitions of complementary companies, assets and lines of businesses will continue to play an important role in our business strategy. While there are currently no unannounced agreements or ongoing negotiations for the acquisition of any material businesses or assets, such transactions can be effected quickly and may occur at any time.

Critical Accounting Policies

Our Accounting Department is responsible for the development and application of our accounting policies and internal control procedures and reports to the Chief Financial Officer.

The process and preparation of our financial statements in conformity with generally accepted accounting principles in the United States (“GAAP”) requires us to make certain estimates, judgments and assumptions, which may affect the reported amounts of our assets and liabilities, disclosures of contingencies at the balance sheet date, the amounts of revenues and expenses recognized during the reporting period and the presentation of our statement of cash flows. We may record materially different amounts if these estimates, judgments and assumptions change or if actual results differ. However, we analyze our estimates, assumptions and judgments based on our historical experience and various other factors that we believe to be reasonable under the circumstances.

We have identified the following critical accounting policies that require a significant amount of estimation or judgment to accurately present our financial position, results of operations and cash flows:

•

Revenue recognition;

•

Estimate of reserves for workers’ compensation, vehicular liability and other self-insurance;

•

Contingencies;

•

Income taxes;

•

Estimates of depreciable lives;

•

Valuation of indefinite-lived intangible assets;

•

Valuation of tangible and finite-lived intangible assets; and

•

Valuation of equity-based compensation.

Revenue Recognition

We recognize revenue when all of the following criteria have been met: (i) evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the price to the customer is fixed and determinable and (iv) collectability is reasonably assured.

•

Evidence of an arrangement exists when a final understanding between us and our customer has occurred, and can be evidenced by a completed customer purchase order, field ticket, supplier contract, or master service agreement.

Delivery has occurred or services have been rendered when we have completed requirements pursuant to the terms of the arrangement as evidenced by a field ticket or service log.

•

The price to the customer is fixed and determinable when the amount that is required to be paid is agreed upon. Evidence of the price being fixed and determinable is evidenced by contractual terms, our price book, a completed customer purchase order, or a field ticket.

•

Collectability is reasonably assured when we screen our customers and provide goods and services to customers according to determined credit terms that have been granted in accordance with our credit policy.

We present our revenues net of any sales taxes collected by us from our customers that are required to be remitted to local or state governmental taxing authorities.

We review our contracts for multiple element revenue arrangements. Deliverables will be separated into units of accounting and assigned fair value if they have standalone value to our customer, have objective and reliable evidence of fair value, and delivery of undelivered items is substantially controlled by us. We believe that the negotiated prices for deliverables in our services contracts are representative of fair value since the acceptance or non-acceptance of each element in the contract does not affect the other elements.

Workers’ Compensation, Vehicular Liability and Other Self-Insurance

The occurrence of an event not fully insured or indemnified against, or the failure of a customer or insurer to meet its indemnification or insurance obligations, could result in substantial losses. In addition, insurance may not be available to cover any or all of these risks, and, if available, we might not be able to obtain such insurance without a substantial increase in premiums. It is possible that, in addition to higher premiums, future insurance coverage may be subject to higher deductibles and coverage restrictions.

We estimate our liability arising out of uninsured and potentially insured events, including workers’ compensation, employer’s liability, vehicular liability, and general liability, and record accruals in our consolidated financial statements. Reserves related to claims are based on the specific facts and circumstances of the insured event and our past experience with similar claims and trend analysis. We adjust loss estimates in the calculation of these accruals based upon actual claim settlements and reported claims. Loss estimates for individual claims are adjusted based upon actual claim judgments, settlements and reported claims. The actual outcome of these claims could differ significantly from estimated amounts. Changes in our assumptions and estimates could potentially have a negative impact on our earnings.

We are primarily self-insured against physical damage to our property, rigs, equipment and automobiles due to large deductibles or self-insurance.

Contingencies

We are periodically required to record other loss contingencies, which relate to lawsuits, claims, proceedings and tax-related audits in the normal course of our operations, on our consolidated balance sheet. We record a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. We periodically review our loss contingencies to ensure that we have recorded appropriate liabilities on the balance sheet. We adjust these liabilities based on estimates and judgments made by management with respect to the likely outcome of these matters, including the effect of any applicable insurance coverage for litigation matters. Our estimates and judgments could change based on new information, changes in laws or regulations, changes in management’s plans or intentions, the outcome of legal proceedings, settlements or other factors. Actual results could vary materially from these reserves.

We record liabilities when environmental assessment indicates that site remediation efforts are probable and the costs can be reasonably estimated. We measure environmental liabilities based, in part, on relevant past experience, currently enacted laws and regulations, existing technology, site-specific costs and cost-sharing arrangements. Recognition of any joint and several liability is based upon our best estimate of our final pro-rata share of such liability or the low amount in a range of estimates. These assumptions involve the judgments and estimates of management, and any changes in assumptions or new information could lead to increases or decreases in our ultimate liability, with any such changes recognized immediately in earnings.

We record legal obligations to retire tangible, long-lived assets on our balance sheet as liabilities, which are recorded at a discount when we incur the liability. Significant judgment is involved in estimating our future cash flows associated with such obligations, as well as the ultimate timing of the cash flows. If our estimates on the amount or timing of the cash flows change, the change may have a material impact on our results of operations.

We account for deferred income taxes using the asset and liability method and provide income taxes for all significant temporary differences. Management determines our current tax liability as well as taxes incurred as a result of current operations, yet deferred until future periods. Current taxes payable represent our liability related to our income tax return for the current year, while net deferred tax expense or benefit represents the change in the balance of deferred tax assets and liabilities reported on our consolidated balance sheets. Management estimates the changes in both deferred tax assets and liabilities using the basis of assets and liabilities for financial reporting purposes and for enacted rates that management estimates will be in effect when the differences reverse. Further, management makes certain assumptions about the timing of temporary tax differences for the differing treatment of certain items for tax and accounting purposes or whether such differences are permanent. The final determination of our tax liability involves the interpretation of local tax laws, tax treaties, and related authorities in each jurisdiction as well as the significant use of estimates and assumptions regarding the scope of future operations and results achieved and the timing and nature of income earned and expenditures incurred.

We establish valuation allowances to reduce deferred tax assets if we determine that it is more likely than not (e.g., a likelihood of more than 50%) that some or all of the deferred tax assets will not be realized in future periods. To assess the likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which this taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted results, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry. Additionally, we record uncertain tax positions at their net recognizable amount, based on the amount that management deems is more likely than not to be sustained upon ultimate settlement with the tax authorities in the domestic and international tax jurisdictions in which we operate.

If our estimates or assumptions regarding our current and deferred tax items are inaccurate or are modified, these changes could have potentially material negative impacts on our earnings.

Estimates of Depreciable Lives

We use the estimated depreciable lives of our long-lived assets, such as rigs, heavy-duty trucks and trailers, to compute depreciation expense, to estimate future asset retirement obligations and to conduct impairment tests. We base the estimates of our depreciable lives on a number of factors, such as the environment in which the assets operate, industry factors including forecasted prices and competition, and the assumption that we provide the appropriate amount of capital expenditures while the asset is in operation to maintain economical operation of the asset and prevent untimely demise to scrap. The useful lives of our intangible assets are determined by the years over which we expect the assets to generate a benefit based on legal, contractual or other expectations.

We depreciate our operational assets over their depreciable lives to their salvage value, which is generally 10% of the acquisition cost. We recognize a gain or loss upon ultimate disposal of the asset based on the difference between the carrying value of the asset on the disposal date and any proceeds we receive in connection with the disposal.

We periodically analyze our estimates of the depreciable lives of our fixed assets to determine if the depreciable periods and salvage value continue to be appropriate. We also analyze useful lives and salvage value when events or conditions occur that could shorten the remaining depreciable life of the asset. We review the depreciable periods and salvage values for reasonableness, given current conditions. As a result, our depreciation expense is based upon estimates of depreciable lives of the fixed assets, the salvage value and economic factors, all of which require management to make significant judgments and estimates. If we determine that the depreciable lives should be different than originally estimated, depreciation expense may increase or decrease and impairments in the carrying values of our fixed assets may result, which could negatively impact our earnings.

Valuation of Indefinite-Lived Intangible Assets

We periodically review our intangible assets not subject to amortization, including our goodwill, to determine whether an impairment of those assets may exist. These tests must be made on at least an annual basis, or more often if circumstances indicate that the assets may be impaired. These circumstances include, but are not limited to, significant adverse changes in the business climate.

The test for impairment of indefinite-lived intangible assets allows us to first assess the qualitative factors to determine whether it is “more likely than not” that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If our qualitative analysis shows that it is “more likely than not” that the fair value of a reporting unit is less than its carrying amount we will perform the two-step goodwill impairment test. In the first step, a fair value is calculated for each of our reporting units, and that fair value is compared to the current carrying value of the reporting unit, including the reporting unit’s goodwill. If the fair value of the

reporting unit exceeds its carrying value, there is no potential impairment, and the second step is not performed. If the carrying value exceeds the fair value of the reporting unit, then the second step is required.

The second step of the test for impairment compares the implied fair value of the reporting unit’s goodwill to its current carrying value. The implied fair value of the reporting unit’s goodwill is determined in the same manner as the amount of goodwill that would be recognized in a business combination, with the purchase price being equal to the fair value of the reporting unit. If the implied fair value of the reporting unit’s goodwill is in excess of its carrying value, no impairment charge is recorded. If the carrying value of the reporting unit’s goodwill is in excess of its implied fair value, an impairment charge equal to the excess is recorded.

In determining the fair value of our reporting units, we use a weighted-average approach of three commonly used valuation techniques — a discounted cash flow method, a guideline companies method, and a similar transactions method. We assigned a weight to the results of each of these methods based on the facts and circumstances that are in existence for that testing period. We assigned more weight to the discounted cash flow method as we believe it is more representative of the future of the business.

In addition to the estimates made by management regarding the weighting of the various valuation techniques, the creation of the techniques themselves requires that we make significant estimates and assumptions. The discounted cash flow method, which was assigned the highest weight by management during the current year, requires us to make assumptions about future cash flows, future growth rates, tax rates in future periods, book-tax differences in the carrying value of our assets in future periods, and discount rates. The assumptions about future cash flows and growth rates are based on our current budgets for future periods, as well as our strategic plans, the beliefs of management about future activity levels, and analysts’ expectations about our revenues, profitability and cash flows in future periods. The assumptions about our future tax rates and book-tax differences in the carrying value of our assets in future periods are based on the assumptions about our future cash flows and growth rates, and management’s knowledge of and beliefs about tax law and practice in current and future periods. The assumptions about discount rates include an assessment of the specific risk associated with each reporting unit being tested, and were developed with the assistance of a third-party valuation consultant. The ultimate conclusions of the valuation techniques remain our responsibility.

The decline in market value of our stock during the third quarter of 2015 as well as the persistent low oil prices and the affect that low oil prices have on our industry were determined to be triggering events making it necessary to perform testing for possible goodwill impairment for our U.S. Rig Services, Coiled Tubing Services, Fishing and Rental Services, Fluid Management Services and International segments. Our analysis concluded that the remaining $561.0 million of goodwill of these segments was fully impaired.

We also have intangible assets that are not amortized of $0.9 million related to our Russian reporting unit in our

International segment. These tradenames are tested for impairment annually using a relief from royalty method.

Valuation of Tangible and Finite-Lived Intangible Assets

Our fixed assets and finite-lived intangibles are tested for potential impairment when circumstances or events indicate a possible impairment may exist. These circumstances or events are referred to as “trigger events” and examples of such trigger events include, but are not limited to, an adverse change in market conditions, a significant decrease in benefits being derived from an acquired business, a change in the use of an asset, or a significant disposal of a particular asset or asset class.

If a trigger event occurs, an impairment test is performed based on an undiscounted cash flow analysis. To perform an impairment test, we make judgments, estimates and assumptions regarding long-term forecasts of revenues and expenses relating to the assets subject to review. Market conditions, energy prices, estimated depreciable lives of the assets, discount rate assumptions and legal factors impact our operations and have a significant effect on the estimates we use to determine whether our assets are impaired. If the results of the analysis indicate that the carrying value of the assets being tested for impairment are not recoverable, then we record an impairment charge to write the carrying value of the assets down to their fair value. Using different judgments, assumptions or estimates, we could potentially arrive at a materially different fair value for the assets being tested for impairment, which may result in an impairment charge.

We have granted stock options, stock-settled stock appreciation rights (“SARs”), restricted stock (“RSAs” and “RSUs”) and performance units to our employees and non-employee directors. The option and SAR awards we grant are fair valued using a Black-Scholes option model on the grant date and are amortized to compensation expense over the vesting period of the option or SAR award, net of estimated and actual forfeitures. Compensation related to RSAs and RSUs is based on the fair value of the award on the grant date and is recognized based on the vesting requirements that have been satisfied during the period. The grant-date fair value of our restricted stock awards is determined using our stock price on the grant date. Performance units provide a cash incentive award, the unit value of which is determined with reference to our common stock. See “Note 19. Share Based Compensation” in“Item 8. Financial Statements and Supplementary Data”for a more detailed discussion of performance units measurement.

In utilizing the Black-Scholes option pricing model to determine fair values of stock options and SARs awards, certain assumptions are made which are based on subjective expectations, and are subject to change. A change in one or more of these assumptions would impact the expense associated with future grants. These key assumptions include the volatility in the price of our common stock, the risk-free interest rate and the expected life of awards. We did not grant any stock options during the years ended December 31, 2015, 2014 and 2013.

Recent Accounting Developments

ASU 2015-17. In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes (Topic 740). The objective of this ASU is to simplify the current guidance which requires entities to separately present deferred tax assets and liabilities as current and non-current in a classified balance sheet. The new guidance will require entities to present deferred tax assets and liabilities as non-current in a classified balance sheet. ASU 2015-17 is effective for fiscal years beginning after December 15, 2016, and interim periods within those years, and may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. We are currently evaluating the standard to determine the impact of its adoption on the consolidated financial statements.

ASU 2015-03. In April 2015, the FASB issued ASU 2015-03,Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The objective of this ASU is to simplify presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. The ASU is effective for annual periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. We adopted ASU 2015-03 in the second quarter of 2015 using the retrospective transition method. As a result, $10.7 million of unamortized deferred financing costs on our December 31, 2014 balance sheet was reclassified from non-current assets to a direct deduction of long-term debt. The adoption of this standard did not affect our results of operations or cash flows.

ASU 2014-09. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). The objective of this ASU is to establish the principles to report useful information to users of financial statements about the nature, amount, timing, and uncertainty of revenue from contracts with customers. The core principle is to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 must be adopted using either a full retrospective method or a modified retrospective method. During a July 2015 meeting, the FASB affirmed a proposal to defer the effective date of the new revenue standard for all entities by one year. As a result, ASU 2014-09 is effective for the Company for interim and annual reporting periods beginning after December 15, 2017 with early adoption permitted for interim and annual reporting periods beginning after December 15, 2016. We are currently evaluating the standard to determine the impact of its adoption on the consolidated financial statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to certain market risks as part of our ongoing business operations, including risks from changes in interest rates, foreign currency exchange rates and equity prices that could impact our financial position, results of operations and cash flows. We manage our exposure to these risks through regular operating and financing activities, and may, on a limited basis, use derivative financial instruments to manage this risk. Derivative financial instruments were not used in the years ended December 31, 2015, 2014 and 2013. To the extent that we use such derivative financial instruments, we will use them only as risk management tools and not for speculative investment purposes.

Interest Rate Risk

As of December 31, 2015, we had outstanding $675.0 million of 2021 Notes. These notes are fixed-rate obligations, and as such do not subject us to risks associated with changes in interest rates. Borrowings under our Term Loan Facility bear interest at variable interest rates, and therefore expose us to interest rate risk. As of December 31, 2015, the interest rate on our

outstanding variable-rate debt obligations was 10.25%. A hypothetical 10% increase in that rate would increase the annual interest expense on those instruments by $3.2 million. Borrowings under our ABL Facility also bear interest at variable interest rates, however, there are no borrowings under this facility.

Foreign Currency Risk

As of December 31, 2015, we conduct operations in Mexico and Russia. We also have a Canadian subsidiary. The local currency is the functional currency for our operations in Russia. For balances denominated in our Russian subsidiaries’ local currency, changes in the value of their assets and liabilities due to changes in exchange rates are deferred and accumulated in other comprehensive income until we liquidate our investment. Our Russian foreign subsidiaries must remeasure their account balances at the end of each period to an equivalent amount of U.S. dollars, with changes reflected in earnings during the period. A hypothetical 10% decrease in the average v